10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

 Commission file number 0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota	27-0383995
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

215 South Cascade Street,  Box 496,   Fergus Falls, Minnesota	56538-0496
(Address of principal executive offices)	(Zip Code)

866-410-8780

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T  (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.:

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date:

April 30, 2015 – 37,483,725 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I.   Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – March 31, 2015 and December 31, 2014 (not audited)	2 & 3
	Consolidated Statements of Income - Three Months Ended March 31, 2015 and 2014 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2015 and 2014 (not audited)	5
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2015 and 2014  (not audited)	6
	Condensed Notes to Consolidated Financial Statements (not audited)	7-32
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33-45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	46
Part II.  Other Information
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	47
Signatures		47

1

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	March 31, 2015		December 31, 2014
ASSETS
Current Assets
Cash and Cash Equivalents	$	157	$	--
Accounts Receivable:
Trade—Net		74,071		60,172
Other		14,406		13,179
Inventories		84,515		85,203
Deferred Income Taxes		52,065		49,482
Unbilled Revenues		15,199		17,996
Regulatory Assets		20,352		25,273
Other		6,935		7,187
Assets of Discontinued Operations		33,171		48,657
Total Current Assets		300,871		307,149
Investments		10,405		8,582
Other Assets		30,900		30,111
Goodwill		31,488		31,488
Other Intangibles—Net		11,113		11,251
Deferred Debits
Unamortized Debt Expense		4,130		4,300
Regulatory Assets		127,368		129,868
Total Deferred Debits		131,498		134,168
Plant
Electric Plant in Service		1,560,459		1,545,112
Nonelectric Operations		178,289		175,159
Construction Work in Progress		269,999		248,677
Total Gross Plant		2,008,747		1,968,948
Less Accumulated Depreciation and Amortization		709,842		700,418
Net Plant		1,298,905		1,268,530
Total Assets	$	1,815,180	$	1,791,279

See accompanying condensed notes to consolidated financial statements.

2

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	March 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
Current Liabilities
Short-Term Debt	$	48,652		$	10,854
Current Maturities of Long-Term Debt		204			201
Accounts Payable		95,876			107,013
Accrued Salaries and Wages		12,826			19,256
Accrued Taxes		15,342			13,793
Derivative Liabilities		11,567			14,230
Other Accrued Liabilities		8,890			8,793
Liabilities of Discontinued Operations		20,732			27,559
Total Current Liabilities		214,089			201,699
Pensions Benefit Liability		93,084			102,711
Other Postretirement Benefits Liability		54,100			53,638
Other Noncurrent Liabilities		24,485			26,794
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		239,999			230,810
Deferred Tax Credits		25,914			26,384
Regulatory Liabilities		77,851			77,013
Other		947			975
Total Deferred Credits		344,711			335,182
Capitalization
Long-Term Debt, Net of Current Maturities		498,437			498,489
Cumulative Preferred Shares– Authorized 1,500,000 Shares Without Par Value; Outstanding - None		--			--
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding - None		--			--
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares;
Outstanding, 2015—37,422,959 Shares; 2014—37,218,053 Shares		187,115			186,090
Premium on Common Shares		284,341			278,436
Retained Earnings		119,340			112,903
Accumulated Other Comprehensive Loss		(4,522	)		(4,663	)
Total Common Equity		586,274			572,766
Total Capitalization		1,084,711			1,071,255
Total Liabilities and Equity	$	1,815,180		$	1,791,279

See accompanying condensed notes to consolidated financial statements.

3

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended March 31,
(in thousands, except share and per-share amounts)	2015			2014
Operating Revenues
Electric	$	113,533		$	119,048
Product Sales		89,308			95,918
Total Operating Revenues		202,841			214,966
Operating Expenses
Production Fuel - Electric		14,599			22,030
Purchased Power - Electric System Use		23,692			21,785
Electric Operation and Maintenance Expenses		37,527			34,622
Cost of Products Sold (depreciation included below)		71,498			73,939
Other Nonelectric Expenses		12,463			9,951
Depreciation and Amortization		14,535			14,267
Property Taxes - Electric		3,502			2,971
Total Operating Expenses		177,816			179,565
Operating Income		25,025			35,401
Interest Charges		7,743			6,595
Other Income		572			1,535
Income Before Income Taxes – Continuing Operations		17,854			30,341
Income Tax Expense – Continuing Operations		4,073			8,562
Net Income from Continuing Operations		13,781			21,779
Discontinued Operations
Loss - net of Income Tax Benefit of $1,376 and $225 for the respective periods		(2,072	)		(349	)
Impairment Loss - net of Income Tax Benefit of $0 for the three months ended March 31, 2015		(1,000	)		--
Gain on Disposition - net of Income Tax Expense of $4,816 for the three months ended March 31, 2015		7,226			--
Net Income (Loss) from Discontinued Operations		4,154			(349	)
Net Income		17,935			21,430
Average Number of Common Shares Outstanding—Basic		37,243,118			36,240,350
Average Number of Common Shares Outstanding—Diluted		37,497,881			36,431,915
Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	0.37		$	0.60
Discontinued Operations		0.11			(0.01	)
	$	0.48		$	0.59
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	0.37		$	0.60
Discontinued Operations		0.11			(0.01	)
	$	0.48		$	0.59
Dividends Declared Per Common Share	$	0.3075		$	0.3025

See accompanying condensed notes to consolidated financial statements

4

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended March 31,
(in thousands)	2015			2014
Net Income	$	17,935		$	21,430
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period		(3	)		(17	)
Gains (Losses) Arising During Period		32			(17	)
Income Tax (Expense) Benefit		(10	)		12
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		19			(22	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		204			50
Income Tax (Expense)		(82	)		(20	)
Pension and Postretirement Benefit Plans – net-of-tax		122			30
Total Other Comprehensive Income		141			8
Total Comprehensive Income	$	18,076		$	21,438

See accompanying condensed notes to consolidated financial statements.

5

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Three Months Ended March 31,
(in thousands)	2015			2014
Cash Flows from Operating Activities
Net Income	$	17,935		$	21,430
Adjustments to Reconcile Net Income to Net Cash Used in Operating Activities:
Net Gain from Sale of Discontinued Operations		(7,226	)		--
Net Loss from Discontinued Operations		3,072			349
Depreciation and Amortization		14,535			14,267
Deferred Tax Credits		(470	)		(454	)
Deferred Income Taxes		7,038			13,073
Change in Deferred Debits and Other Assets		3,538			(888	)
Discretionary Contribution to Pension Plan		(10,000	)		(20,000	)
Change in Noncurrent Liabilities and Deferred Credits		41			(2,408	)
Allowance for Equity/Other Funds Used During Construction		(256	)		(340	)
Change in Derivatives Net of Regulatory Deferral		(59	)		118
Stock Compensation Expense—Equity Awards		623			358
Other—Net		206			182
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(11,288	)		(22,329	)
Change in Inventories		688			(9,236	)
Change in Other Current Assets		1,270			437
Change in Payables and Other Current Liabilities		(20,185	)		(7,731	)
Change in Interest and Income Taxes Receivable/Payable		(1,549	)		1,013
Net Cash Used in Continuing Operations		(2,087	)		(12,159	)
Net Cash Used in Discontinued Operations		(6,263	)		(6,898	)
Net Cash Used in Operating Activities		(8,350	)		(19,057	)
Cash Flows from Investing Activities
Capital Expenditures		(35,738	)		(37,311	)
Net Proceeds from Disposal of Noncurrent Assets		1,292			848
Net Increase in Other Investments		(3,492	)		(989	)
Net Cash Used in Investing Activities - Continuing Operations		(37,938	)		(37,452	)
Net Proceeds from Sale of Discontinued Operations		21,343			--
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations		(1,759	)		285
Net Cash Used in Investing Activities		(18,354	)		(37,167	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(1,236	)		--
Net Short-Term Borrowings (Repayments)		37,798			(39,296	)
Proceeds from Issuance of Common Stock – net of Issuance Expenses		4,697			3,666
Payments for Retirement of Capital Stock		(1,239	)		(242	)
Proceeds from Issuance of Long-Term Debt		--			150,000
Short-Term and Long-Term Debt Issuance Expenses		(4	)		(502	)
Payments for Retirement of Long-Term Debt		(49	)		(40,946	)
Dividends Paid and Other Distributions		(11,498	)		(10,993	)
Net Cash Provided by Financing Activities – Continuing Operations		28,469			61,687
Net Cash Used in Financing Activities – Discontinued Operations		(1,178	)		--
Net Cash Provided by Financing Activities		27,291			61,687
Net Change in Cash and Cash Equivalents - Discontinued Operations		(430	)		(126	)
Net Change in Cash and Cash Equivalents		157			5,337
Cash and Cash Equivalents at Beginning of Period		--			2,007
Cash and Cash Equivalents at End of Period	$	157		$	7,344

See accompanying condensed notes to consolidated financial statements.

6

OTTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014. Because of seasonal and other factors, the earnings for the three months ended March 31, 2015 should not be taken as an indication of earnings for all or any part of the balance of the year.

The following condensed notes are numbered to correspond to numbers of the notes included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

1. Summary of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.

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 Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (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.

7

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 March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	381
Investments:
Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
Corporate Debt Securities – Held by Captive Insurance Company				6,625
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,229
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
Total Assets	$	2,550	$	7,854	$	381
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	282	$	--
Derivative Liabilities - Forward Energy Contracts						11,285
Total Liabilities	$	--	$	282	$	11,285

December 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	257
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				6,761
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,253
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
Total Assets	$	713	$	8,014	$	257
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	342	$	--
Derivative Liabilities - Forward Energy Contracts						13,888
Total Liabilities	$	--	$	342	$	13,888

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of March 31, 2015 and December 31, 2014, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The March 31, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour.

8

In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three month periods ended March 31, 2015 and 2014.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Forward Energy Contracts - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2015		2014
Finished Goods	$	27,607	$	27,998
Work in Process		9,894		10,628
Raw Material, Fuel and Supplies		47,014		46,577
Total Inventories	$	84,515	$	85,203

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table summarizes changes to goodwill by business segment during 2015:

(in thousands)	Gross Balance December 31, 2014		Accumulated Impairments		Balance (net of impairments) December 31, 2014		Adjustments to Goodwill in 2015		Balance (net of impairments) March 31, 2015
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Total	$	31,488	$	--	$	31,488	$	--	$	31,488

9

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,996	$	10,815	57-157 months
Other Intangible Assets Including Contracts		639		447		192	18 months
Emission Allowances		106		--		106	Expensed as used
Total	$	17,556	$	6,443	$	11,113
December 31, 2014(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,784	$	11,027	60-160 months
Other Intangible Assets Including Contracts		639		415		224	21 months
Total	$	17,450	$	6,199	$	11,251

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2015		2016		2017		2018		2019
Estimated Amortization Expense – Intangible Assets	$	977	$	945	$	849	$	849	$	849

The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015:

	Three Months Ended
(in thousands)	March 31, 2015
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(62	)
Emission Allowances Ending Balance	$	106

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2015		2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	32,838	$	22,244
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554	$	3,434
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.

10

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2015 could be as high as $28.5 million.

New Accounting Standards

ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016,however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.

ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03),which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015.

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ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements.

2. Segment Information

The Company’s businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. These businesses sell products and provide services to customers primarily in the United States. The three segments are: Electric, Manufacturing and Plastics.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is an active wholesale participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

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

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

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

No single customer accounted for over 10% of the Company’s consolidated revenues in 2014. All of the Company’s long-lived assets are within the United States.

The following table presents the percent of consolidated sales revenue by country:

	Three Months Ended March 31,
	2015			2014
United States of America		96.3	%		97.2	%
Mexico		3.0	%		2.2	%
Canada		0.6	%		0.5	%
All Other Countries (none individually greater than 0.05%)		0.1	%		0.1	%

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The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2015 and 2014 and total assets by business segment as of March 31, 2015 and December 31, 2014 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	113,547		$	119,088
Manufacturing		56,759			55,435
Plastics		32,552			40,483
Intersegment Eliminations		(17	)		(40	)
Total	$	202,841		$	214,966

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Electric	$	6,121	$	5,079
Manufacturing		832		808
Plastics		246		247
Corporate and Intersegment Eliminations		544		461
Total	$	7,743	$	6,595

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	4,221		$	5,750
Manufacturing		504			1,671
Plastics		1,264			2,133
Corporate		(1,916	)		(992	)
Total	$	4,073		$	8,562

Net Income

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	13,178		$	16,653
Manufacturing		1,184			2,896
Plastics		2,120			3,460
Corporate		(2,701	)		(1,230	)
Discontinued Operations		4,154			(349	)
Total	$	17,935		$	21,430

Identifiable Assets

	March 31,		December 31,
(in thousands)	2015		2014
Electric	$	1,484,289	$	1,472,647
Manufacturing		139,143		130,701
Plastics		90,256		87,356
Corporate		68,321		51,918
Assets of Discontinued Operations		33,171		48,657
Total	$	1,815,180	$	1,791,279

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3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2015 and 2014.

Major Capital Expenditure Projects

Big Stone Plant Air Quality Control System (AQCS)—The South Dakota Department of Environmental and Natural Resources determined that the Big Stone Plant is subject to Best-Available Retrofit Technology (BART) requirements of the Clean Air Act, based on air dispersion modeling indicating that Big Stone Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan.

OTP is currently in the final stages of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through March 31, 2015 is $174.9 million, excluding Allowance for Funds Used During Construction (AFUDC).

Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. The St. Cloud to Alexandria portion of the Fargo Project was placed into service on April 23, 2014. The third and final phase of the Fargo Project, from Alexandria to Fargo, was energized on April 2, 2015.

Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—The MISO granted unconditional approval of the Brookings Project as a Multi-Value Project (MVP) under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011.The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized in April 2014. This line was placed into service on March 26, 2015.

The Big Stone South – Brookings MVP and CapX2020 Project—This is a planned 345 kV transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013 and granted approval of a route permit for the southern portion of the line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017.

The Big Stone South – Ellendale MVP—This is a proposed 345 kV transmission line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU).  MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019.

Recovery of OTP’s transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

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Reagent Costs and Emission Allowances

OTP’s system wide costs for reagents and Cross-State Air Pollution Rule (CSAPR) emissions allowances are expected to increase to approximately $4.1 million annually, $3.6 million for reagents and $0.5 million for emission allowances. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs will be phased in during 2015 and 2016 when the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects are completed and in service. Emissions allowance costs are being incurred during 2015 to maintain compliance with CSAPR rules, which became effective January 1, 2015.

Minnesota

2010 General Rate Case—OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. 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%.

Minnesota Conservation Improvement Programs (MNCIP)—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 September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. Based on results from the 2014 MNCIP program year, OTP now estimates a financial incentive for 2014 of $3.0 million. OTP is estimating a lower incentive for 2014 in response to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016.  Additionally, OTP estimated it saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. OTP requested approval for recovery of its 2014 MNCIP financial incentive and 2014 program costs not included in base rates from the MPUC in an April 1, 2015 filing.

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. OTP filed its annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of Certificate of Need estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015.
 

Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. OTP filed its 2014 annual update on July 31, 2014, requesting a $4.1 million annual increase in the rider from $6.1 million to $10.2 million. The MPUC approved OTP’s ECR rider annual update request on November 24, 2014, effective December 1, 2014. Because the effective date was two months behind the anticipated implementation date for the updated rate and a portion of the requested increase had been collected under the initial rate, the approved updated rate is based on a revenue requirement of $9.8 million. The rate will continue to be updated in annual filings with the MPUC until the costs are rolled into base rates at an undetermined future date.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs will be reviewed in OTP’s next general rate case in Minnesota and considered for recovery either through the FCA rider or general rates.

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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.Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

Renewable Resource Adjustment—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 with a return on investment at the level approved in OTP’s most recent general rate case. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the updated rates implemented on April 1, 2013. The NDPSC approved OTP’s 2013 annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. OTP submitted its 2014 annual update to the NDRRA on December 31, 2014, which was approved by the NDPSC on March 25, 2015 with an effective date of April 1, 2015. In each instance the NDRRA rates have been based upon a return on investment at the rate of return approved in the OTP’s last general rate case. Approved in the 2014 annual update was a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill.

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. For qualifying projects, the law authorizes a current return on construction work in progress and a return on investment at the level approved in the utility’s most recent general rate case. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million. The NDPSC approved the annual update on December 17, 2014 with an effective date of January 1, 2015.

Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. The ECR provides for a current return on construction work in progress and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR with a proposed implementation date of July 1, 2015.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through the modification of the ECR rider to add a new variable monthly reagent and emissions allowance charge effective May 1, 2015.

South Dakota

2010 General Rate Case—On April 21, 2011, the SDPUC issued a written order approving an overall revenue increase for OTP of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50%. Final rates were effective with bills rendered on and after June 1, 2011.

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s following annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s most recent annual update on February 13, 2015 with an effective date of March 1, 2015.

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Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s jurisdictional share of costs and provide a return on investment for the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014.

Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended March 31,
Rate Rider (in thousands)	2015		2014
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,928	$	1,521
Transmission Cost Recovery		1,615		2,304
Environmental Cost Recovery		2,557		1,763
North Dakota
Renewable Resource Adjustment		1,883		1,435
Transmission Cost Recovery		1,936		1,514
Environmental Cost Recovery		2,156		1,522
Big Stone II Project Costs		--		361
South Dakota
Transmission Cost Recovery		363		346
Environmental Cost Recovery		504		--
1Includes MNCIP costs recovered in base rates.

FERC

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the return on equity (ROE) component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. Settlement discussions did not resolve the dispute and the FERC set the proceeding to a Track II Hearing for complex cases that can take several months to decide with a FERC decision anticipated in fall 2016 at the earliest. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the resolution of the return on equity complaint proceeding.

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from the current 12.38% to a proposed 8.67%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. As of April 30, 2015, the FERC had not responded to the complaint.

In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.

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4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations (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:

	March 31, 2015						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,465	$	99,659	$	107,124	see below
Deferred Marked-to-Market Losses1		2,059		9,226		11,285	69 months
Conservation Improvement Program Costs and Incentives2		3,815		3,511		7,326	27 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,305		5,305	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		2,152		1,835		3,987	12 months
Big Stone II Unrecovered Project Costs – Minnesota1		601		3,086		3,687	93 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,140		636		2,776	24 months
Debt Reacquisition Premiums1		351		1,802		2,153	210 months
Deferred Income Taxes1		--		1,461		1,461	asset lives
Recoverable Fuel and Purchased Power Costs1		1,249		--		1,249	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		718		818	98 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		420		--		420	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
North Dakota Renewable Resource Rider Accrued Revenues2		--		61		61	12 months
Total Regulatory Assets	$	20,352	$	127,368	$	147,720
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,220	$	75,220	asset lives
North Dakota Renewable Resource Rider Accrued Refund		1,803		--		1,803	12 months
Deferred Income Taxes		--		1,447		1,447	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		908		908	see below
Minnesota Environmental Cost Recovery Rider Accrued Refund		451		--		451	12 months
Deferred Marked-to-Market Gains		204		177		381	58 months
Big Stone II Over Recovered Project Costs – North Dakota		111		--		111	9 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		99		105	225 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		86		--		86	12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		35		--		35	12 months
Total Regulatory Liabilities	$	2,744	$	77,851	$	80,595
Net Regulatory Asset Position	$	17,608	$	49,517	$	67,125
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.

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	December 31, 2014						Remaining Recovery/ Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see below
Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		943		2,455		3,398	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
Debt Reacquisition Premiums1		351		1,890		2,241	213 months
Deferred Income Taxes1		--		2,086		2,086	asset lives
Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		859		--		859	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
Total Regulatory Assets	$	25,273	$	129,868	$	155,141
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
Deferred Income Taxes		--		1,550		1,550	asset lives
North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see below
Deferred Marked-to-Market Gains		--		257		257	67 months
Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
Net Regulatory Asset Position	$	24,115	$	52,855	$	76,970
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 March 31, 2015 are related to forward purchases of energy scheduled for delivery through December 2020.

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

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

Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 2015.

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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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 210 months.

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

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

North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of March 31, 2015.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2015.

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

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2015.

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

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS projectthat are refundable to Minnesota customers as of March 31, 2015.

Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of the North Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2015.

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2015.

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investment in the Big Stone Plant AQCS projectthat are refundable to North Dakota customers as of March 31, 2015.

If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases.

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5. Forward Contracts Classified as Derivatives

Electricity Contracts

All of OTP’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. OTP’s objective in entering into forward contracts for the purchase and sale of energy is to meet the energy requirements of its retail customers and to optimize the use of its generating and transmission facilities. OTP’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. Prior to December 2014, OTP also entered into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales. Effective December 31, 2014 OTP discontinued its trading activities not directly associated with serving retail customers.

OTP’s forward contracts outstanding as of March 31, 2015 and December 31, 2014 for the purchase of electricity are scheduled for delivery at the OTP node, which is an illiquid trading point. Prices used to value OTP’s forward purchases at this trading point were based on a basis spread between the OTP node and more liquid trading hub prices. These basis spreads were determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into Level 3 of the fair value hierarchy set forth in ASC 820.

The following tables show the effect of marking to market OTP’s forward contracts for the purchase of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of March 31, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to March 31, 2015 and December 31, 2013 to March 31, 2014:

(in thousands)	March 31, 2015			December 31, 2014
Current Asset – Marked-to-Market Gain	$	381		$	257
Regulatory Asset – Current Deferred Marked-to-Market Loss		2,059			4,492
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,226			9,396
Total Assets		11,666			14,145
Current Liability – Marked-to-Market Loss		(11,285	)		(13,888	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(204	)		--
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(177	)		(257	)
Total Liabilities		(11,666	)		(14,145	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--

(in thousands)	Year-to-Date March 31, 2015		Year-to-Date March 31, 2014
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	--	$	115
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		--		(72	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--		(43	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--		--
Changes in Fair Value of Contracts Entered into in Current Period		--		39
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--	$	39

The following realized and unrealized net loss on forward energy contracts is included in electric operating revenues on the Company’s consolidated statements of income:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Net Loss on Forward Electric Energy Contracts	$	--	$	(4	)

OTP has established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at March 31, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.

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Individual counterparty exposures for certain contracts can be offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of March 31, 2015 and December 31, 2014 are indicated in the following table:

(in thousands)	March 31, 2015			December 31, 2014
Derivative assets subject to legally enforceable netting arrangements	$	381		$	257
Derivative liabilities subject to legally enforceable netting arrangements		(11,567	)		(14,230	)
Net balance subject to legally enforceable netting arrangements	$	(11,186	)	$	(13,973	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of March 31, 2015 and December 31, 2014:

Current Liability – Marked-to-Market Loss  (in thousands)	March 31, 2015			December 31, 2014
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	282		$	45
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,285			13,888
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			297
Total Current Liability – Marked-to-Market Loss	$	11,567		$	14,230
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	$	11,285		$	13,888
Offsetting Gains with Counterparties under Master Netting Agreements		(381	)		(257	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,904		$	13,631

6. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share

Reconciliation of Common Shareholders’ Equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2014	$	186,090		$	278,436		$	112,903		$	(4,663	)	$	572,766
Common Stock Issuances, Net of Expenses		1,220			6,302									7,522
Common Stock Retirements		(195	)		(1,044	)								(1,239	)
Net Income								17,935						17,935
Other Comprehensive Income											141			141
Tax Benefit – Stock Compensation					24									24
Employee Stock Incentive Plans Expense					623									623
Common Dividends ($0.3075 per share)								(11,498	)					(11,498	)
Balance, March 31, 2015	$	187,115		$	284,341		$	119,340		$	(4,522	)	$	586,274

Shelf Registration

The Company’s shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 11, 2012, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 10, 2015. On May 14, 2012, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.

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Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2014 through March 31, 2015:

Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Executive Stock Performance Awards (2012-2014 shares earned)	89,991
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	42,518
Cash Invested	16,553
At-the-Market Offering	38,160
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	5,985
Employee Stock Ownership Plan	21,137
Stock Options Exercised	9,000
Vesting of Restricted Stock Units	700
Retirements:
Shares Withheld for Individual Income Tax Requirements	(39,131	)
Common Shares Outstanding, March 31, 2015	37,422,959

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 2015 and 2014. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation of Weighted Average Common Shares Outstanding – Basic to Weighted Average Common Shares Outstanding – Diluted for the three month periods ended March 31:

	2015			2014
Weighted Average Common Shares Outstanding – Basic		37,243,118			36,240,350
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		229,100			131,000
Nonvested Restricted Shares		83,330			90,798
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		70,900			55,655
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		40,462			39,197
Potentially Dilutive Stock Options		3,750			18,050
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(169,842	)		(127,709	)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(2,937	)		(15,426	)
Total Dilutive Shares		254,763			191,565
Weighted Average Common Shares Outstanding – Diluted		37,497,881			36,431,915

The effect of dilutive shares on earnings per share for the three month periods ended March 31, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

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7. Share-Based Payments

Stock Incentive Awards

On February 6, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s executive officers under the 2014 Stock Incentive Plan.

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	December 31, 2017
Restricted Stock Units Granted to Executive Officers:
Graded Vesting		20,900	$	31.675	25% per year through February 6, 2019
Cliff Vesting		6,400	$	31.675	100% on February 6, 2020

Under the performance share awards the aggregate award for performance at target is 77,500 shares. For target performance the Company’s executive officers would earn an aggregate of 51,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2015 through December 31, 2017. The Company’s executive officers would also earn an aggregate of 25,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 116,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC Topic 718, Compensation–Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

Under the 2015 performance award agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be made at target at the date of any such event.

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement or, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

As of March 31, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2015 and 2014 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2015		2014
Employee Stock Purchase Plan (15% discount)	$	49	$	42
Restricted Stock Granted to Directors		98		123
Restricted Stock Granted to Executive Officers		157		135
Restricted Stock Units Granted to Non-Executive Employees		66		58
Restricted Stock Units Granted to Executive Officers		253		--
Stock Performance Awards Granted to Executive Officers		1,020		526
Totals	$	1,643	$	884

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8. Retained Earnings Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends 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 March 31, 2015 the Company was in compliance with the debt covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2014 for further information on the covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 45.0% and 55.0%. OTP’s equity to total capitalization ratio including short-term debt was 50.7% as of March 31, 2015. Total capitalization for OTP cannot currently exceed $987 million.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2014 OTP had commitments under contracts in connection with construction programs extending into 2018 of approximately $106.6 million. At March 31, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $106.1 million.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2039. In the first quarter of 2015, OTP entered into an energy purchase agreement for the purchase of electricity in April, May and June of 2015 to make up for reduced generation from Coyote Station as it continues to make repairs related to damage caused by a boiler feed pump failure and ensuing fire in December 2014. The total cost for the replacement power will be approximately $2.9 million.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2015, 2016, 2017 and 2040. In the first quarter of 2015, OTP entered into a second contract for the purchase of Wyoming subbituminous coal to meet a portion of its 2015 through 2017 coal requirements at Big Stone Plant. OTP’s share of the purchase commitment under this contract as of March 31, 2015 is approximately $10.0 million. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs.

Operating Leases

In April of 2015, OTP entered into an agreement to extend the term of its lease of rail cars used for the transport of coal to Hoot Lake Plant by 36 months beginning April 1, 2015, for a total commitment of approximately $2.8 million.

Contingencies

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $5.0 million.

In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.

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On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes. Under the other proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for nonhazardous solid wastes. On December 19, 2014 the EPA announced a final rule following the Subtitle D nonhazardous provisions. Publication of the final rule on April 17, 2015 opened a 90-day window within which petitions for judicial review may be filed in the D.C. Circuit. Challenges by environmental groups are possible and the outcome of such challenges cannot be predicted. Thus, uncertainty regarding the status of this rule is likely to continue for a period of time. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. The cost impact of this rule will not be known until those actions are completed. As of the date of this report on From 10-Q, OTP had not completed its assessment under the final rule nor made a determination if compliance with the rule would require immediate remediation or result in the recognition of additional AROs beyond those already recognized by OTP in connection with its active and inactive ash disposal sites.  Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. The EPA is also considering future regulation of coal ash under Subtitle C.

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 March 31, 2015 will not be material.

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10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of March 31, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on March 31, 2015		Restricted due to Outstanding Letters of Credit		Available on March 31, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
OTP Credit Agreement		170,000		7,806		560		161,634		169,440
Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	7,806	$	40,846	$	48,652
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		237		237
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,074		1,074
Total	$	445,000	$	53,641	$	498,641
Less: Current Maturities		--		204		204
Total Long-Term Debt	$	445,000	$	53,437	$	498,437
Total Short-Term and Long-Term Debt (with current maturities)	$	452,806	$	94,487	$	547,293

December 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	10,854	$	10,854
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330	$	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,105		1,105
Total	$	445,000	$	53,691	$	498,691
Less: Current Maturities		--		201		201
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,489	$	498,489
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544

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11. Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company’s noncontributory funded pension plan are as follows:

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	1,500		$	1,175
Interest Cost on Projected Benefit Obligation		3,325			3,285
Expected Return on Assets		(4,600	)		(4,187	)
Amortization of Prior-Service Cost:
From Regulatory Asset		47			64
From Other Comprehensive Income1		1			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,633			868
From Other Comprehensive Income1		40			23
Net Periodic Pension Cost	$	1,946		$	1,230
1Corporate cost included in Other Nonelectric Expenses.

Cash flows—The Company made discretionary plan contributions totaling $10,000,000 in January 2015. The Company currently is not required and does not expect to make an additional contribution to the plan in 2015. The Company also made discretionary plan contributions totaling $20,000,000 in January 2014.

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three Months Ended March 31,
(in thousands)	2015		2014
Service Cost—Benefit Earned During the Period	$	47	$	13
Interest Cost on Projected Benefit Obligation		381		380
Amortization of Prior-Service Cost:
From Regulatory Asset		4		5
From Other Comprehensive Income1		10		13
Amortization of Net Actuarial Loss:
From Regulatory Asset		83		35
From Other Comprehensive Income2		151		12
Net Periodic Pension Cost	$	676	$	458
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	4	$	5
Other Nonelectric Expenses		6		8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	78	$	33
Other Nonelectric Expenses		73		(21	)

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	375		$	315
Interest Cost on Projected Benefit Obligation		550			558
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		48			--
From Other Comprehensive Income1		1			--
Net Periodic Postretirement Benefit Cost	$	1,026		$	925
Effect of Medicare Part D Subsidy	$	(450	)	$	(308	)
1 Corporate cost included in Other Nonelectric Expenses.

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12. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 2015 and December 31, 2014 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.

Long-Term Debt including Current Maturities—The fair value of the Company’s and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

	March 31, 2015						December 31, 2014
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	157		$	157		$	--		$	--
Short-Term Debt		(48,652	)		(48,652	)		(10,854	)		(10,854	)
Long-Term Debt including Current Maturities		(498,641	)		(571,801	)		(498,690	)		(600,828	)

14. Income Tax Expense – Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended March 31,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,054	)		(2,252	)
Section 199 Domestic Production Activities Deduction		(362	)		(358	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
AFUDC Equity		(100	)		(133	)
Corporate Owned Life Insurance		(80	)		(112	)
Other Items – Net		90			(15	)
Income Tax Expense – Continuing Operations	$	4,073		$	8,562
Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2015		2014
Balance on January 1	$	222	$	4,239
Increases Related to Tax Positions for Prior Years		--		137
Increases Related to Tax Positions for Current Year		44		--
Uncertain Positions Resolved During Year		--		--
Balance on March 31	$	266	$	4,376

The balance of unrecognized tax benefits as of March 31, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2015 is not expected to change significantly within the next twelve months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. No interest is accrued on tax uncertainties as of March 31, 2015.

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The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of March 31, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2011. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at March 31, 2015 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014.

16. Discontinued Operations

In 2014 the Company entered into signed letters of intent to sell its two construction companies that made up its Construction segment. On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor headquartered in Kansas City, Missouri, for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) in exchange for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets to be determined within 90 days of closing. The Company recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. The assets, liabilities, operating results and cash flows of Foley and AEV, Inc. are being reported as discontinued operations as of, and for the periods preceding, March 31, 2015. On February 8, 2013 the Company completed the sale of substantially all the assets of its former waterfront equipment manufacturing company previously included in the Company’s Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing company. The following summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2015 and 2014, include the operating results of Foley, AEV, Inc. and residual expenses from the Company’s former wind tower and waterfront equipment manufacturers:

	For the Three Months Ended March 31,
(in thousands)	2015			2014
Operating Revenues	$	18,724		$	25,506
Operating Expenses		22,141			26,368
Goodwill Impairment Charge		1,000			--
Operating Loss		(4,417	)		(862	)
Other (Deductions) Income		(31	)		288
Income Tax Benefit		(1,376	)		(225	)
Net Loss from Operations		(3,072	)		(349	)
Gain on Disposition Before Taxes		12,042			--
Income Tax Expense on Disposition		4,816			--
Net Gain on Disposition		7,226			--
Net Income (Loss)	$	4,154		$	(349	)

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2015 and December 31, 2014:

(in thousands)	March 31, 2015		December 31, 2014
Current Assets	$	26,928	$	35,174
Goodwill and Intangibles		1,814		2,814
Net Plant		4,429		10,669
Assets of Discontinued Operations	$	33,171	$	48,657
Current Liabilities	$	15,616	$	22,864
Deferred Income Taxes		5,116		4,695
Liabilities of Discontinued Operations	$	20,732	$	27,559

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Foley and AEV, Inc.entered into fixed-price construction contracts. Revenues under these contracts have been 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.

The following tables summarize costs incurred and billings and estimated earnings recognized on uncompleted contracts included in current assets and current liabilities of discontinued operations:

	March 31,			December 31,
(in thousands)	2015			2014
Costs Incurred on Uncompleted Contracts	$	339,594		$	402,332
Less Billings to Date		(354,256	)		(411,909	)
Plus Estimated Earnings Recognized		14,458			15,154
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

	March 31,			December 31,
(in thousands)	2015			2014
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,216		$	8,133
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(3,420	)		(2,556	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

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. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in $2.3 million in pretax charges in the first quarter of 2015.

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge as a result of a revision in the estimated valuation of Foley due to first quarter financial results. The first quarter 2015 goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations.

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

(in thousands)	2015			2014
Warranty Reserve Balance, January 1	$	2,527		$	3,087
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(6	)		--
Decrease in Warranty Estimates for Prior Years		--			(100	)
Warranty Reserve Balance, March 31	$	2,521		$	2,987

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The warranty reserve balances as of March 31, 2015 relate entirely to warranties scheduled to expire over the next five years on products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products these companies produced prior to the companies being sold. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction companies that have been retained by customers pending project completion:

	March 31,		December 31,
(in thousands)	2015		2014
Accounts Receivable Retained by Customers	$	4,018	$	6,759

17. Subsequent Events

Sale of Foley

On April 30, 2015 the Company completed the sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. Although the net carrying value of Foley had been adjusted to its indicated fair value through goodwill impairment charges recorded prior to the sale based on acceptance of the buyer’s offering price, the final proceeds and loss on sale will not be known until the adjustments for working capital and other related items have been determined.

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Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

Following is an analysis of the operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three months ended March 31, 2015 and 2014, followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2015 and our business outlook for the remainder of 2015.

Comparison of the Three Months Ended March 31, 2015 and 2014

Consolidated operating revenues were $202.8 million for the three months ended March 31, 2015 compared with

$215.0 million for the three months ended March 31, 2014. Operating income was $25.0 million for the three months ended March 31, 2015 compared with $35.4 million for the three months ended March 31, 2014. The Company recorded diluted earnings per share from continuing operations of $0.37 for the three months ended March 31, 2015 compared with $0.60 for the three months ended March 31, 2014, and total diluted earnings per share of $0.48 for the three months ended March 31, 2015 compared with $0.59 for the three months ended March 31, 2014.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three month periods ended March 31, 2015 and 2014 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	March 31, 2015		March 31, 2014
Operating Revenues:
Electric	$	14	$	40
Nonelectric		3		--
Cost of Products Sold		--		2
Other Nonelectric Expenses		17		38

Electric

	Three Months Ended
	March 31,								%
(in thousands)	2015		2014			Change			Change
Retail Sales Revenues	$	103,614	$	105,504		$	(1,890	)		(1.8	)
Wholesale Revenues – Company Generation		1,060		4,900			(3,840	)		(78.4	)
Net Revenue – Energy Trading Activity		127		(269	)		396			147.2
Other Revenues		8,746		8,953			(207	)		(2.3	)
Total Operating Revenues	$	113,547	$	119,088		$	(5,541	)		(4.7	)
Production Fuel		14,599		22,030			(7,431	)		(33.7	)
Purchased Power – System Use		23,692		21,785			1,907			8.8
Other Operation and Maintenance Expenses		37,527		34,622			2,905			8.4
Depreciation and Amortization		11,064		10,763			301			2.8
Property Taxes		3,502		2,971			531			17.9
Operating Income	$	23,163	$	26,917		$	(3,754	)		(13.9	)
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,361,683		1,397,891			(36,208	)		(2.6	)
Wholesale kwh Sales – Company Generation		36,097		73,305			(37,208	)		(50.8	)
Wholesale kwh Sales – Purchased Power Resold		20		1,611			(1,591	)		(98.8	)
Heating Degree Days		3,337		4,089			(752	)		(18.4	)

The $1.9 million decrease in retail revenue includes:

● A $3.3 million decrease in revenues due to much milder winter weather in 2015 compared with 2014, which was the main factor contributing to the 2.6% decrease in retail kilowatt-hour (kwh) sales.

33

● A $1.6 million decrease in fuel clause adjustment (FCA) revenues and fuel and purchased power costs recovered in base rates related to decreased kwh sales and lower costs recoverable through the FCA, all factors that were impacted by the milder winter of 2015.

● A $0.4 million reduction in Big Stone II Cost Recovery rider revenues as the North Dakota share of abandoned plant costs were fully recovered as of March 31, 2014.

offset by:

● A $1.9 million increase in Environmental Cost Recovery (ECR) rider revenues related to earning a return in North Dakota and Minnesota on increasing amounts invested in the air quality control system (AQCS) under construction at Big Stone Plant, and the initiation of an ECR rider in South Dakota in December 2014 to recover costs and earn a return on amounts invested in the Big Stone Plant AQCS and the Hoot Lake Plant Mercury and Air Toxics Standards project.

● A $1.0 million increase in revenue from kwh sales to customers whose demand was not negatively impacted by the weather, mainly pipeline operators.

● A $0.5 million increase in revenues in the first quarter of 2015 related to an increase in conservation program incentives recoverable under the Minnesota Conservation Improvement Program rider.

Wholesale electric revenues from company-owned generation decreased $3.8 million as a result of a 56.1% decrease in revenue per wholesale kwh sold combined with a 50.8% decrease in sales volume. The decrease in wholesale kwh sales and prices was driven by decreased wholesale market demand resulting from much milder weather in the first quarter of 2015. Also, Otter Tail Power Company (OTP) had fewer resources available for selling into the wholesale market as Coyote Station was operating at reduced load due to a December 2014 boiler feed pump failure and ensuing fire, and Big Stone Plant was taken off line February 27, 2015 for a planned spring outage. Additionally, Hoot Lake Plant was curtailed for economic dispatch reasons related to low market prices for electricity and generation from company-owned wind turbines was down 9.8% from the first quarter of 2014due to icing, scheduled repairs and lower average wind speed in the first quarter of 2015.

Production fuel costs decreased $7.4 million as a result of a 30.3% decrease in kwhs generated from OTP’s steam-powered and combustion turbine generators primarily due to the factors discussed above. The cost of purchased power to serve retail customers increased $1.9 million due to a 43.1% increase in kwhs purchased, partially offset by a 24.0% decrease in the cost per kwh purchased. The increase in power purchases for retail sales was necessitated by the reduced availability of company-owned generating capacity discussed above. The decreased cost per kwh purchased was driven by lower market demand mainly resulting from the milder winter weather in 2015.

Electric operating and maintenance expenses increased $2.9 million mainly as a result of:

● A $1.6 million increase in external service costs related to maintenance work being performed during Big Stone Plant’s extended spring maintenance which began February 27, 2015 in conjunction with tying in the new AQCS.

● A $0.8 million increase in Midcontinent Independent System Operator, Inc. (MISO) transmission service charges related to increasing investments in regional CapX2020 and MISO-designated Multi-Value Projects.

● A $0.5 million increase in expenditures for vegetation maintenance and control around power lines.

● A $0.4 million increase in labor benefit costs, mainly related to an increase in corporate costs allocated to utility operations.

offset by:

● A $0.4 million reduction in the amortization of the North Dakota share of Big Stone II abandoned plant costs which were fully recovered as of March 31, 2014.

Depreciation expense increased $0.3 million as a result of increased investment in transmission, distribution and general plant placed in service in 2014 and 2015.

The $0.5 million increase in property tax expense was due to higher assessed values of property in Minnesota and South Dakota in combination with increasing investments in transmission and distribution property, mainly in Minnesota.

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Manufacturing

	Three Months Ended
	March 31,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	56,759	$	55,435	$	1,324			2.4
Cost of Products Sold		45,699		42,199		3,500			8.3
Operating Expenses		5,938		5,225		713			13.6
Depreciation and Amortization		2,592		2,620		(28	)		(1.1	)
Operating Income	$	2,530	$	5,391	$	(2,861	)		(53.1	)

The increase in revenues in our Manufacturing segment reflects the following:

● Revenues at BTD Manufacturing, Inc. (BTD), our metal parts stamping and fabrication company, increased $0.5 million primarily as a result of increased demand in recreational and lawn and garden equipment end markets, offset by reductions in demand in agriculture and wind energy equipment end markets, lower tooling revenues and a decrease in revenue from the sale of scrap-metal due to commodity price reductions.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased $0.8 million. While sales volume for horticultural products was flat quarter over quarter, an increase in sales of higher priced products relative to a decrease in sales of lower priced products resulted in a $0.4 million increase in horticultural sales revenues. An increase in sales of various other products to industrial customers also contributed $0.4 million to the increase in revenue.

The increase in cost of products sold in our Manufacturing segment relates to the following:

● Cost of products sold at BTD increased $2.3 million, including a $1.8 million increase in material costs related to increased sales combined with lower productivity efficiencies and a $0.5 million increase in benefit costs.

● Cost of products sold at T.O. Plastics increased $1.2 million including a $0.9 million increase in material and labor costs related to the increase in sales and a $0.3 million increase in shipping costs, mainly related to less than full load shipments of horticultural products to meet customer demand and delivery dates.

The increase in operating expenses in our Manufacturing segment is mostly due to a $0.6 million increase in employee benefit expenses at BTD.

Plastics

	Three Months Ended
	March 31,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	32,552	$	40,483	$	(7,931	)		(19.6	)
Cost of Products Sold		25,799		31,742		(5,943	)		(18.7	)
Operating Expenses		2,290		2,117		173			8.2
Depreciation and Amortization		848		853		(5	)		(0.6	)
Operating Income	$	3,615	$	5,771	$	(2,156	)		(37.4	)

The $7.9 million decrease in Plastic segment revenues is the result of a 20.6% decrease in pounds of polyvinyl chloride (PVC) pipe sold due, in part, to delayed purchases related to falling resin prices, partially offset by a 1.3% increase in the price per pound of pipe sold. The decrease in sales was geographically dispersed with the most significant decreases occurring in Texas, Minnesota, North Dakota, Kansas and Arizona. The $5.9 million decrease in costs of products sold is due to the decrease in sales volume, partially offset by a 2.4% increase in the cost per pound of pipe sold related to higher labor, benefit and fixed overhead costs per pound of PVC pipe produced and sold. A $0.2 million increase in operating expenses was mainly related to an increase in wage and benefit costs.

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Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

	Three Months Ended
	March 31,						%
(in thousands)	2015		2014		Change		Change
Operating Expenses	$	4,252	$	2,647	$	1,605		60.6
Depreciation and Amortization		31		31		--		--

Corporate operating expenses increased $1.6 million due to:

● A $1.0 million increase in health care related benefit costs.

● A $0.8 million increase in stock-based compensation incentive costs, mainly related to accelerated vesting for certain employees being eligible for retirement.

● A $0.4 million increase in costs related to leadership development and leadership succession.

offset by:

● A net increase in corporate costs allocated to utility operations of approximately $0.7 million related to the increase in corporate benefit and stock incentive costs and higher allocation rates resulting from recent divestitures of nonutility operations.

Interest Charges

The $1.1 million increase in interest charges in the first three months of 2015 compared with the first three months of 2014 reflects:

● a $1.3 million increase in interest expense incurred in January and February of 2015 at OTP related to the February 27, 2014 issuance of $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044.

offset by:

● A $0.2 million reduction in interest expense related to the February 27, 2014 repayment of OTP’s $40.9 million unsecured term loan under a Credit Agreement with JPMorgan Chase Bank, N.A., which bore interest at LIBOR plus 0.875% and a reduction in the daily average balance of short-term debt outstanding between quarters. OTP used a portion of the proceeds from the issuance of the Series A and B Senior Unsecured Notes referenced above to repay $82.5 million of short-term debt then outstanding under the OTP Credit Agreement.

Other Income

The $1.0 million decrease in other income in the three months ended March 31, 2015 compared with the three months ended March 31, 2014, reflects a $0.8 million gain on the sale of an investment in tax-credit-qualified low income housing rental property in the first quarter of 2014 that was not duplicated in the first quarter of 2015 along with a $0.2 million reduction in other income at OTP related to reductions in allowances for funds used during construction and other miscellaneous income.

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Income Taxes – Continuing Operations

Income tax expense - continuing operations decreased $4.5 million mainly as a result of a $12.5 million decrease in income from continuing operations before income taxes between the first quarter of 2015 and the first quarter of 2014. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on our consolidated statements of income for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended March 31,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(2,054	)		(2,252	)
Section 199 Domestic Production Activities Deduction		(362	)		(358	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
AFUDC Equity		(100	)		(133	)
Corporate Owned Life Insurance		(80	)		(112	)
Other Items – Net		90			(15	)
Income Tax Expense – Continuing Operations	$	4,073		$	8,562
Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs decreased 9.1% due to icing, scheduled repairs and lower average wind speed in the three months ended March 31, 2015 compared with the three months ended March 31, 2014. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Discontinued Operations

In 2014 we entered into signed letters of intent to sell our two construction companies that made up our Construction segment. On April 30, 2015 we sold Foley Company (Foley), our former water, wastewater, power and industrial construction contractor for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. Although the net carrying value of Foley had been adjusted to its indicated fair value through goodwill impairment charges recorded prior to the sale based on acceptance of the buyer’s offering price, the final proceeds and loss on sale will not be known until the adjustments for working capital and other related items have been determined. On February 28, 2015 we sold the assets of our former energy and electrical construction contractor (AEV, Inc.) in exchange for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets to be determined within 90 days of closing. We recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. On February 8, 2013 we completed the sale of substantially all the assets of our former waterfront equipment manufacturing company previously included in the our Manufacturing segment. On November 30, 2012 we completed the sale of the assets of our former wind tower manufacturing company. The following summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2015 and 2014, include the operating results of Foley, AEV, Inc. and residual expenses from our former wind tower and waterfront equipment manufacturers:

	For the Three Months Ended March 31,
(in thousands)	2015			2014
Operating Revenues	$	18,724		$	25,506
Operating Expenses		22,141			26,368
Goodwill Impairment Charge		1,000			--
Operating Loss		(4,417	)		(862	)
Other (Deductions) Income		(31	)		288
Income Tax Benefit		(1,376	)		(225	)
Net Loss from Operations		(3,072	)		(349	)
Gain on Disposition Before Taxes		12,042			--
Income Tax Expense on Disposition		4,816			--
Net Gain on Disposition		7,226			--
Net Income (Loss)	$	4,154		$	(349	)

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FINANCIAL POSITION

The following table presents the status of our lines of credit as of March 31, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on March 31, 2015		Restricted due to Outstanding Letters of Credit		Available on March 31, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
OTP Credit Agreement		170,000		7,806		560		161,634		169,440
Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312

We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects.

Equity or debt financing will be required in the period 2015 through 2019 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. Our operating cash flow and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. 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 our subsidiaries. See note 8 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 3, 2015 our board of directors increased the quarterly dividend from $0.3025 to $0.3075 per common share.

Cash used in operating activities of continuing operations was $2.1 million for the three months ended March 31, 2015 compared with $12.2 million for the three months ended March 31, 2014. The main contributing factor to the $10.1 million reduction in cash used in operating activities was a $10.0 million decrease in discretionary contributions to our pension plan between the quarters. An $8.0 million decrease in net income from continuing operations was mostly offset by a $6.8 million reduction in cash used for working capital items between the quarters. In the Plastics segment net cash used for accounts receivable and inventory decreased $16.0 million in the first quarter of 2015 compared with the first quarter of 2014, which corresponds with lower production and a 20.6% reduction in sales volume between the quarters. The $16.0 million decrease in cash used for accounts receivable and inventory buildup was partially offset by a $12.2 million increase in cash used for accounts payable in the Plastics segment, which is also related to a decrease in production activity in the first quarter of 2015 compared to more sustained levels of production in the first quarter of 2014.

In continuing operations, net cash used in investing activities was $37.9 million for the three months ended March 31, 2015 compared with $37.5 million for the three months ended March 31, 2014. A $2.5 million increase in cash used for investments between quarters was mostly offset by a $1.6 million decrease in cash used for capital expenditures. The increase in cash used for investments between the quarters mainly reflects the deposit of $2.0 million in proceeds from the sale of the assets of AEV, Inc. in the first quarter of 2015 into an escrow account. The $1.6 million decrease in cash used for capital expenditures includes a $6.4 million decrease in cash used for capital expenditures in our Electric segment, as work was completed on two major transmission line projects in 2015 and work begins to wind down on the Big Stone Plant AQCS, offset by a $4.5 million increase in capital expenditures at BTD as it moves forward with its project to expand and realign its Minnesota production and warehouse facilities, which was initiated in the fourth quarter of 2014.

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First quarter 2015 investing activities of discontinued operations includes $21.3 million in cash proceeds from the sale of the assets of AEV, Inc., partially offset by $1.8 million in cash used in investing activities of discontinued operations, mainly related to the purchase, by AEV, Inc., of assets being leased under operating leases prior to the assets being sold.

Net cash provided by financing activities was $28.5 million for the three months ended March 31, 2015 compared with $61.7 million for the three months ended March 31, 2014. Net cash provided by financing activities in the first quarter of 2015 includes $37.8 million in short-term borrowings used, in part, to fund capital expenditures, offset by $11.5 million in common stock dividend payments.  Net cash provided by financing activities in the first quarter of 2014 mainly reflects the issuance by OTP of $150 million in privately placed unsecured notes in two series on February 27, 2014, and the use of a portion of the proceeds of the notes to retire OTP’s $40.9 million unsecured term loan and to repay short-term debt outstanding under the OTP Credit Agreement which was being used to finance OTP’s construction activities. First quarter 2014 financing activities also reflect the payment of $11.0 million in common stock dividends, OTP’s repayment of  $51.2 million in short-term debt outstanding under the OTP Credit Agreement on December 31, 2013 and the borrowing of $11.9 million under the Otter Tail Corporation Credit Agreement to fund the working capital needs of our manufacturing and infrastructure companies.

CAPITAL REQUIREMENTS

2015-2019 Capital Expenditures

The following table shows our 2014 capital expenditures and 2015 through 2019 anticipated capital expenditures and electric utility average rate base:

(in millions)	2014		2015		2016		2017		2018		2019
Capital Expenditures:
Electric Segment:
Transmission			$	55	$	90	$	56	$	58	$	40
Environmental				56		3		--		--		--
Other				40		42		39		79		107
Total Electric Segment	$	149	$	151	$	135	$	95	$	137	$	147
Manufacturing and Plastics Segments		15		32		16		19		27		16
Total Capital Expenditures	$	164	$	183	$	151	$	114	$	164	$	163
Total Electric Utility Average Rate Base			$	957	$	1,017	$	1,070	$	1,118	$	1,196

Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2015 through 2019 timeframe.

Contractual Obligations

Our contractual obligations reported in the table on page 51 of our Annual Report on Form 10-K for the year ended December 31, 2014 increased $15.7 million in the first quarter of 2015. Our purchase obligations under coal contract commitments increased $1.3 million for 2015 and $8.7 million for 2016 and 2017 as a result of OTP entering into a contract in the first quarter of 2015 for the purchase of coal to meet a portion of Big Stone Plant’s future coal requirements. Our obligations related to capacity and energy requirements increased $2.9 million for 2015 as a result of OTP entering into an energy purchase agreement in the first quarter of 2015 for the purchase of electricity in April, May and June of 2015 to make up for reduced generation at Coyote Station. Our operating lease obligations increased $0.7 million in 2015, $1.9 million in 2016 and 2017 and $0.2 million in 2018 as a result of OTP entering into an agreement in April 2015 to extend the term of its lease of rail cars used for the transport of coal to Hoot Lake Plant by 36 months, beginning April 1, 2015.

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CAPITAL RESOURCES

On May 11, 2012 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 10, 2015. On May 14, 2012, we entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million. In the first quarter of 2015 we received proceeds of $1,223,000 net of $25,000 paid to JPMS from the issuance of 38,160 common shares under this program. We are in the process of preparing to file a new shelf registration statement with the SEC and entering into a new Distribution Agreement with JPMS in May 2015.

Short-Term Debt

The following table presents the status of our lines of credit as of March 31, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on March 31, 2015		Restricted due to Outstanding Letters of Credit		Available on March 31, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
OTP Credit Agreement		170,000		7,806		560		161,634		169,440
Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $150 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On November 3, 2014 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2018 to October 29, 2019. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of our subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our senior unsecured credit ratings. We are 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 us and the businesses of the Company’s wholly owned subsidiary, Varistar Corporation, and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On November 3, 2014 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2018 to October 29, 2019. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

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Long-Term Debt

2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the Purchasers named therein, pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes. OTP used a portion of the proceeds of the Notes to retire its $40.9 million term loan under a Credit Agreement with JPMorgan Chase Bank, N.A. and to repay $82.5 million of short-term debt then outstanding under the OTP Credit Agreement. Remaining proceeds of the Notes were used to fund OTP construction program expenditures.

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement).

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

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Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of March 31, 2015.

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.

Our borrowing agreements are subject to certain financial covenants. Specifically:

● Under the Otter Tail Corporation Credit Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our 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. As of March 31, 2015 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 3.24 to 1.00.

● Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

● Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of March 31, 2015 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.04 to 1.00.

● 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.

As of March 31, 2015 our ratio of interest-bearing debt to total capitalization was 0.48 to 1.00 on a consolidated basis and 0.49 to 1.00 for OTP.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $6.0 million, but our line of credit borrowing limits are only restricted by $0.8 million of the outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

2015 BUSINESS OUTLOOK

We are revising our consolidated diluted earnings per share guidance for 2015 to be in the range of $1.50 to $1.65 from our previously announced range of $1.65 to $1.80. This updated guidance reflects the current mix of businesses owned by us. It considers the cyclical nature of some of our businesses and reflects challenges, as well as our plans and strategies for improving future operating results.

Segment components of our 2014 diluted earnings per share and 2015 diluted earnings per share guidance range for continuing operations are as follows:

	2014			2015 Guidance February 9, 2015						2015 Guidance Revised May 4, 2015
Diluted Earnings Per Share				Low			High			Low			High
Electric	$	1.19		$	1.26		$	1.29		$	1.23		$	1.26
Manufacturing	$	0.25		$	0.37		$	0.41		$	0.21		$	0.25
Plastics	$	0.33		$	0.25		$	0.29		$	0.29		$	0.33
Corporate	$	(0.22	)	$	(0.23	)	$	(0.19	)	$	(0.23	)	$	(0.19	)
Total – Continuing Operations	$	1.55		$	1.65		$	1.80		$	1.50		$	1.65
Expected Return on Equity											9.5	%		10.4	%

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Contributing to our updated earnings guidance for 2015 are the following items:

● We expect 2015 net income for our Electric segment to decrease from our previously issued guidance primarily as a result of the lower than expected first quarter earnings, driven in part by warmer than normal weather, but also due to higher than expected claim costs and more participants associated with the long-term disability plans and an increase in coal plant reagent costs that were determined unrecoverable under rider by the Minnesota Public Utilities Commission in March 2015.

Other items affecting our 2015 Electric segment earnings guidance compared with 2014 earnings include:

○    Rider recovery increases, including environmental riders in Minnesota, North Dakota and South Dakota related to the Big Stone AQCS environmental upgrades while under construction.

○    Expected increases in sales to pipeline and commercial customers.

○    A decrease in plant maintenance costs, as unanticipated maintenance issues encountered during the 2014 Hoot Lake shutdown are not expected to occur in 2015.

offset by:

○    A decrease in transmission revenues for a potential reduction in the rate of return on equity granted by the Federal Energy Regulatory Commission under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff.

○    An increase in pension costs as a result of an increase in projected benefit obligations based on a decrease in the discount rate from 5.30% to 4.35% and adoption of new mortality tables which have longer life expectancy assumptions.

○    Higher depreciation and property tax expense due to increased investment in transmission, generation, distribution and general plant placed in service in 2014 and 2015.

○    Higher short-term interest costs as major projects continue to be funded.

● We are lowering our previous 2015 net income guidance from our Manufacturing segment due to:

○    A softness in the agriculture, energy, mining and oil and gas equipment end markets served by BTD’s customers, declining commodity prices for scrap, increased costs of manufacturing due to lower productivity and increased severance costs relating to workforce reductions at BTD’s manufacturing plants.

○    While we are lowering our guidance based on revised expectations for BTD, we expect earnings from T.O. Plastics to be better than projected in our original guidance based on an expected increase in sales of custom products.

○    Backlog for the manufacturing companies of approximately $106 million for 2015 compared with $115 million one year ago.

● We are increasing our 2015 net income guidance from our Plastics segment due to lower than expected increases in raw material costs which will result in higher operating margins than originally projected. Sales volumes are expected to be slightly lower than 2014 levels.

● Corporate costs are still expected to be flat in 2015 compared with 2014.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use 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 and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 56 through 60 of our Annual Report on Form 10-K for the year ended December 31, 2014. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2015.

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Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as “may”, “will”, “expect”, “anticipate”, “continue”, “estimate”, “project”, “believes” or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act.These forward-looking statements involve risks and uncertainties.  Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, as well as the various factors described below:

● Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

● Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and could increase borrowing costs and pension plan and postretirement health care expenses.

● We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are not able to access capital at competitive rates, our ability to implement our business plans may be adversely affected.

● Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of our customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.

● We made a $10.0 million discretionary contribution to our defined benefit pension plan in January 2015. We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

● Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

● Declines in projected operating cash flows at any of our reporting units may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

● The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on us.

● Economic conditions could negatively impact our businesses.

● If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

● Our plans to grow and realign our business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance.

● We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses could expose us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

● Our plans to grow and operate our nonutility businesses could be limited by state law.

● Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

● We are subject to risks associated with energy markets.

● We are subject to risks and uncertainties related to the timing and recovery of deferred tax assets which could have a negative impact on our net income in future periods.

● We rely on our information systems to conduct our business and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period of time, our business could be harmed.

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● We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to our shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

● Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

● OTP’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

● Changes to regulation of generating plant emissions, including but not limited to carbon dioxide emissions, could affect OTP’s operating costs and the costs of supplying electricity to its customers.

● Competition from foreign and domestic manufacturers, the price and availability of raw materials and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

● Our Plastics segment is highly dependent on a limited number of vendors for PVC resin, many of which are located in the Gulf Coast region of the United States, and a limited supply of resin. The loss of a key vendor, or an interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this segment.

● Our plastic pipe companies compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish the pipe companies’ products from those of its competitors.

● Changes in PVC resin prices can negatively impact PVC pipe prices, profit margins on PVC pipe sales and the value of PVC pipe held in inventory.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

At March 31, 2015 we had exposure to market risk associated with interest rates because we had $40.8 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 1.75% under our $150 million revolving credit facility, and OTP had $7.8 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.25% under its $170 million revolving credit facility.

All of our consolidated long-term debt outstanding on March 31, 2015 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum and polystyrene (PS) and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

We have in place an energy risk management policy with a goal to manage, through the use of defined risk management practices, price risk and credit risk associated with wholesale power sales. We have established guidelines and limits to manage credit risk associated with wholesale power and capacity sales. Specific limits are determined by a counterparty’s financial strength. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at March 31, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.

45

Item 4.  Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of March 31, 2015, the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2015.

During the fiscal quarter ended March 31, 2015, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

The Company is the subject of various pending or threatened legal actions and proceedings in the ordinary course of its business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. The Company records a liability in its consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where it has assessed that a loss is probable and an amount can be reasonably estimated. The Company believes the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.

Item 1A.  Risk Factors

There has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 27 through 33 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The Company does not have a publicly announced stock repurchase program. The following table shows common shares that were surrendered to the Company by employees to pay taxes in connection with shares issued for incentive awards in February 2015 under the Company’s 1999 Stock Incentive Plan: 

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
January 2015		--		--
February 2015		39,131	$	31.675
March 2015		--		--
Total		39,131

46

Item 6.  Exhibits

10.1 Form of 2015 Performance Award Agreement (Executives) (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.2 Form of 2015 Performance Award Agreement (Legacy) (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.3 Form of 2014 Restricted Stock Unit Award Agreement (Executives) (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.4 Form of 2015 Restricted Stock Unit Award Agreement (Legacy) (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.5 Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated (incorporated by reference to Exhibit 10.5 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.6 Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C. (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on March 18, 2015).

31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended March 31, 2015, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Condensed Notes to Consolidated Financial Statements.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

OTTER TAIL CORPORATION
By:	/s/ Kevin G. Moug
	Kevin G. Moug
	Chief Financial Officer
	(Chief Financial Officer/Authorized Officer)

Dated:  May 8, 2015

47

EXHIBIT INDEX

Exhibit Number     Description

10.1 Form of 2015 Performance Award Agreement (Executives) (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.2 Form of 2015 Performance Award Agreement (Legacy) (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.3 Form of 2014 Restricted Stock Unit Award Agreement (Executives) (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.4 Form of 2015 Restricted Stock Unit Award Agreement (Legacy) (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.5 Otter Tail Corporation Executive Restoration Plus Plan, as Amended and Restated (incorporated by reference to Exhibit 10.5 to the Form 8-K filed by Otter Tail Corporation on February 11, 2015).

10.6 Second Amendment to Lignite Sales Agreement dated as of March 16, 2015 among Otter Tail Power Company, Northern Municipal Power Agency, Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., NorthWestern Corporation and Coyote Creek Mining Company, L.L.C. (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by Otter Tail Corporation on March 18, 2015).

31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended March 31, 2015, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Condensed Notes to Consolidated Financial Statements.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles S. MacFarlane, certify that:

1.            I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.            Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.            Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.            The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.            The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2015

/s/ Charles S. MacFarlane

Charles S. MacFarlane

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Moug, certify that:

1.            I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.            Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.            Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.            The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)           designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)           disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.            The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)           all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)           any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2015

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles S. MacFarlane, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles S. MacFarlane  

Charles S. MacFarlane

President and Chief Executive Officer

May 8, 2015

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer

May 8, 2015

XML

Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 3) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Goodwill [Line Items]
Gross Balance December 31, 2014	$ 31,488
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	31,488
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	31,488
Manufacturing
Goodwill [Line Items]
Gross Balance December 31, 2014	12,186
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	12,186
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	12,186
Plastics
Goodwill [Line Items]
Gross Balance December 31, 2014	19,302
Accumulated Impairments
Goodwill [Roll Forward]
Balance (net of impairments) December 31, 2014	19,302
Adjustments to Goodwill in 2015
Balance (net of impairments) March 31,2015	$ 19,302

XML

Rate and Regulatory Matters (Detail Textuals 3) (Otter Tail Power Company, USD $)	1 Months Ended	0 Months Ended	1 Months Ended
	Apr. 21, 2011	Feb. 12, 2015	Nov. 30, 2013	Mar. 31, 2015
South Dakota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority	643,000
Percentage of increase in base rate revenue approved by rate authority	2.32%
South Dakota Public Utilities Commission | 2010 General Rate Case | Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Public utilities allowed rate of return subsequent to approval of increase in base rate	8.50%
Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Proposed reduced return on equity used in transmission rates		8.67%	9.15%
Estimated liability of refund obligation				$ 600,000
Current return on equity used in transmission rates			12.38%

XML

Segment Information - Information on continuing operations for business segments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating Revenue	$ 202,841	$ 214,966
Interest Charges	7,743	6,595
Income Taxes	4,073	8,562
Net Income	17,935	21,430
Identifiable Assets	1,815,180		1,791,279
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(17)	(40)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	544	461
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(1,916)	(992)
Net Income	(2,701)	(1,230)
Identifiable Assets	68,321		51,918
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income	4,154	(349)
Identifiable Assets	33,171		48,657
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	113,547	119,088
Interest Charges	6,121	5,079
Income Taxes	4,221	5,750
Net Income	13,178	16,653
Identifiable Assets	1,484,289		1,472,647
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	56,759	55,435
Interest Charges	832	808
Income Taxes	504	1,671
Net Income	1,184	2,896
Identifiable Assets	139,143		130,701
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	32,552	40,483
Interest Charges	246	247
Income Taxes	1,264	2,133
Net Income	2,120	3,460
Identifiable Assets	$ 90,256		$ 87,356

XML

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details) (Employee Stock Purchase Plan)	3 Months Ended
	Mar. 31, 2015
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense, discount rate	15.00%

XML

Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015		Dec. 31, 2014
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	$ 20,352		$ 25,273
Regulatory Liability - Current	2,744		1,158
Net Regulatory Assets Position - Current	17,608		24,115
Regulatory Assets - Long-Term	127,368		129,868
Regulatory Liabilities - Long-Term	77,851		77,013
Net Regulatory Assets (Liability) Position - Long-Term	49,517		52,855
Regulatory Assets - Total	147,720		155,141
Regulatory Liabilities - Total	80,595		78,171
Net Regulatory Asset Position - Total	67,125		76,970
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	7,465	[1]	7,464	[1]
Regulatory Assets - Long-Term	99,659	[1]	101,526	[1]
Regulatory Assets - Total	107,124	[1]	108,990	[1]
Regulatory Assets - Remaining Recovery/Refund Period	see below	[1]	see below	[1]
Deferred Marked-to-Market Loss
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,059	[1]	4,492	[1]
Regulatory Assets - Long-Term	9,226	[1]	9,396	[1]
Regulatory Assets - Total	11,285	[1]	13,888	[1]
Regulatory Assets - Remaining Recovery/Refund Period	69 months	[1]	72 months	[1]
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	3,815	[2]	5,843	[2]
Regulatory Assets - Long-Term	3,511	[2]	2,500	[2]
Regulatory Assets - Total	7,326	[2]	8,343	[2]
Regulatory Assets - Remaining Recovery/Refund Period	27 months	[2]	18 months	[2]
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Assets - Long-Term	5,305	[1]	5,190	[1]
Regulatory Assets - Total	5,305	[1]	5,190	[1]
Regulatory Assets - 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 Asset - Current	601	[1]	592	[1]
Regulatory Assets - Long-Term	3,086	[1]	3,207	[1]
Regulatory Assets - Total	3,687	[1]	3,799	[1]
Regulatory Assets - Remaining Recovery/Refund Period	93 months	[1]	96 months	[1]
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,140	[1]	2,585	[1]
Regulatory Assets - Long-Term	636	[1]	807	[1]
Regulatory Assets - Total	2,776	[1]	3,392	[1]
Regulatory Assets - Remaining Recovery/Refund Period	24 months		24 months	[1]
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	351	[1]	351	[1]
Regulatory Assets - Long-Term	1,802	[1]	1,890	[1]
Regulatory Assets - Total	2,153	[1]	2,241	[1]
Regulatory Assets - Remaining Recovery/Refund Period	210 months	[1]	213 months	[1]
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[1]		[1]
Regulatory Liability - Current
Regulatory Assets - Long-Term	1,461	[1]	2,086	[1]
Regulatory Liabilities - Long-Term	1,447		1,550
Regulatory Assets - Total	1,461	[1]	2,086	[1]
Regulatory Liabilities - Total	1,447		1,550
Regulatory Assets - Remaining Recovery/Refund Period	asset lives	[1]	asset lives	[1]
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			706	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			706	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
Minnesota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			186	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			186	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]		[2]
Regulatory Assets - Long-Term	68	[2]	68	[2]
Regulatory Assets - Total	68	[2]	68	[2]
Regulatory Assets - Remaining Recovery/Refund Period	see below	[2]	see below	[2]
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term	75,220		74,237
Regulatory Liabilities - Total	75,220		74,237
Regulatory Liabilities - Remaining Recovery/Refund Period	asset lives		asset lives
Deferred Marked-to-Market Gains
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	204
Regulatory Liabilities - Long-Term	177		257
Regulatory Liabilities - Total	381		257
Regulatory Liabilities - Remaining Recovery/Refund Period	58 months		67 months
North Dakota Renewable Resource Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	1,803		933
Regulatory Liabilities - Long-Term			85
Regulatory Liabilities - Total	1,803		1,018
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		15 months
Revenue for Rate Case expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current
Regulatory Liabilities - Long-Term	908		784
Regulatory Liabilities - Total	908		784
Regulatory Liabilities - Remaining Recovery/Refund Period	see below		see below
Big Stone II Over Recovered Project Costs - North Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	111		147
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	111		147
Regulatory Liabilities - Remaining Recovery/Refund Period	9 months		12 months
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	100	[2]	100	[2]
Regulatory Assets - Long-Term	718	[2]	743	[2]
Regulatory Assets - Total	818	[2]	843	[2]
Regulatory Assets - Remaining Recovery/Refund Period	98 months	[2]	101 months	[2]
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current		[2]
Regulatory Assets - Long-Term	61	[2]
Regulatory Assets - Total	61	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]
Deferred Gain on Sale of Utility Property - Minnesota Portion
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	6		6
Regulatory Liabilities - Long-Term	99		100
Regulatory Liabilities - Total	105		106
Regulatory Liabilities - Remaining Recovery/Refund Period	225 months		228 months
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	1,249	[1]	1,114	[1]
Regulatory Assets - Long-Term		[1]		[1]
Regulatory Assets - Total	1,249	[1]	1,114	[1]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[1]	12 months	[1]
South Dakota - Nonasset-Based Margin Sharing Excess
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current			24
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total			24
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	2,152	[2]	943	[2]
Regulatory Assets - Long-Term	1,835	[2]	2,455	[2]
Regulatory Assets - Total	3,987	[2]	3,398	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	24 months	[2]
North Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current	420	[2]	859	[2]
Regulatory Assets - Long-Term		[2]		[2]
Regulatory Assets - Total	420	[2]	859	[2]
Regulatory Assets - Remaining Recovery/Refund Period	12 months	[2]	12 months	[2]
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	451
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	451
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
South Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Asset - Current			38	[2]
Regulatory Assets - Long-Term				[2]
Regulatory Assets - Total			38	[2]
Regulatory Assets - Remaining Recovery/Refund Period			12 months	[2]
South Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	48		48
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	48		48
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months		12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	35
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	35
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability - Current	86
Regulatory Liabilities - Long-Term
Regulatory Liabilities - Total	$ 86
Regulatory Liabilities - Remaining Recovery/Refund Period	12 months

[1] Costs subject to recovery without a rate of return.

[2] Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

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Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	$ 1,500		$ 1,175
Interest Cost on Projected Benefit Obligation	3,325		3,285
Expected Return on Assets	(4,600)		(4,187)
Amortization of Prior-Service Cost:
From Regulatory Asset	47		64
From Other Comprehensive Income	1	[1]	2	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	1,633		868
From Other Comprehensive Income	40	[1]	23	[1]
Net Periodic Pension Cost	1,946		1,230
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	47		13
Interest Cost on Projected Benefit Obligation	381		380
Amortization of Prior-Service Cost:
From Regulatory Asset	4		5
From Other Comprehensive Income	10	[2]	13	[2]
Amortization of Net Actuarial Loss:
From Regulatory Asset	83		35
From Other Comprehensive Income	151	[3]	12	[3]
Net Periodic Pension Cost	676		458
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period	375		315
Interest Cost on Projected Benefit Obligation	550		558
Amortization of Prior-Service Cost:
From Regulatory Asset	51		51
From Other Comprehensive Income	1	[1]	1	[1]
Amortization of Net Actuarial Loss:
From Regulatory Asset	48
From Other Comprehensive Income	1	[1]		[1]
Net Periodic Pension Cost	1,026		925
Effect of Medicare Part D Subsidy	$ (450)		$ (308)

[1] Corporate cost included in Other Nonelectric Expenses.

[2] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8

[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 )

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Summary of Significant Accounting Policies (Detail Textuals 1) (Coyote Creek Mining Company, L.L.C. (CCMC), Lignite Sales Agreement, Otter Tail Power Company, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company
Significant Accounting Policies [Line Items]
Amortization period	52 months
Percentage of development period costs, development fees and capital charge incurred by CCMC	35.00%
Amount of development period costs, development fees and capital charges incurred by CCMC	$ 28.5
Maximum exposure to loss as a result of involvement with CCMC	$ 28.5

XML

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Schedule of long-term debt including current maturities

	March 31, 2015						December 31, 2014
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	157		$	157		$	--		$	--
Short-Term Debt		(48,652	)		(48,652	)		(10,854	)		(10,854	)
Long-Term Debt including Current Maturities		(498,641	)		(571,801	)		(498,690	)		(600,828	)

XML

Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	$ 10	[1]	$ 13	[1]
Amortization of Net Actuarial Loss - From Other Comprehensive Income	151	[2]	12	[2]
Electric operation and maintenance expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	4		5
Amortization of Net Actuarial Loss - From Other Comprehensive Income	78		33
Other nonelectric expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior-Service Cost - From Other Comprehensive Income	6		8
Amortization of Net Actuarial Loss - From Other Comprehensive Income	$ 73		$ (21)

[1] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8

[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 )

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Retained Earnings Restriction (Detail Textuals) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Retained Earnings Restriction [Line Items]
Total Capitalization	$ 1,084,711	$ 1,071,255
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	50.70%
Total Capitalization	$ 987,000
OTP | Minimum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	45.00%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Required equity-to-total-capitalization ratio to limit dividend payment	55.00%

XML

Discontinued Operations - Costs and estimated earnings in excess of billings that are included in consolidated balance sheets (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$ 3,216	$ 8,133
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	(3,420)	(2,556)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (204)	$ 5,577

XML

Forward Contracts Classified as Derivatives - Effect of marking to market forward contracts for purchase and sale of electricity and location and fair value amounts of related derivatives (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	$ 20,352	$ 25,273
Regulatory Assets - Long-Term	127,368	129,868
Current Liability - Marked-to-Market Loss	(11,567)	(14,230)
Regulatory Liability - Current	(2,744)	(1,158)
Regulatory Liabilities - Long-Term	(77,851)	(77,013)
Forward Electricity Contracts
Derivatives, Fair Value [Line Items]
Current Asset - Marked-to-Market Gain	381	257
Total Assets	11,666	14,145
Current Liability - Marked-to-Market Loss	(11,285)	(13,888)
Total Liabilities	(11,666)	(14,145)
Net Fair Value of Marked-to-Market Energy Contracts			39	115
Forward Electricity Contracts | Deferred Marked-to-Market Loss
Derivatives, Fair Value [Line Items]
Regulatory Asset - Current	2,059	4,492
Regulatory Assets - Long-Term	9,226	9,396
Forward Electricity Contracts | Deferred Marked-to-Market Gain
Derivatives, Fair Value [Line Items]
Regulatory Liability - Current	(204)
Regulatory Liabilities - Long-Term	$ (177)	$ (257)

XML

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Short-Term Debt	$ 48,652	$ 10,854
Long-Term Debt	498,641	498,691
Less: Current Maturities	204	201
Unamortized Debt Discount		1
Total Long-Term Debt	498,437	498,489
Total Short-Term and Long-Term Debt (with current maturities)	547,293	509,544
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000	90,000
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	237	256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	1,074	1,105
OTP
Debt Instrument [Line Items]
Short-Term Debt	7,806
Long-Term Debt	445,000	445,000
Less: Current Maturities
Unamortized Debt Discount
Total Long-Term Debt	445,000	445,000
Total Short-Term and Long-Term Debt (with current maturities)	452,806	445,000
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000	60,000
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000	90,000
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	40,846	10,854
Long-Term Debt	53,641	53,691
Less: Current Maturities	204	201
Unamortized Debt Discount		1
Total Long-Term Debt	53,437	53,489
Total Short-Term and Long-Term Debt (with current maturities)	94,487	64,544
Otter Tail Corporation | 9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt	52,330	52,330
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	237	256
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 1,074	$ 1,105

XML

Discontinued Operations - Results of discontinued operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Loss from Operations	$ (3,072)	$ (349)
Income Tax Expense on Disposition	4,816
Net Gain on Disposition	7,226
Net Income (Loss)	4,154	(349)
Disposal groups held for sale or disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Revenues	18,724	25,506
Operating Expenses	22,141	26,368
Goodwill Impairment Charge	1,000
Operating Loss	(4,417)	(862)
Other (Deductions) Income	(31)	288
Income Tax Benefit	(1,376)	(225)
Net Loss from Operations	(3,072)	(349)
Gain on Disposition Before Taxes	12,042
Income Tax Expense on Disposition	4,816
Net Gain on Disposition	7,226
Net Income (Loss)	$ 4,154	$ (349)

XML

Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 157
Short-Term Debt	(48,652)	(10,854)
Long-Term Debt including Current Maturities	(498,641)	(498,690)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Cash and Cash Equivalents	157
Short-Term Debt	(48,652)	(10,854)
Long-Term Debt including Current Maturities	$ (571,801)	$ (600,828)

XML

Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets of Discontinued Operations	$ 33,171	$ 48,657
Liabilities of Discontinued Operations	20,732	27,559
Disposal groups held for sale or disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current Assets	26,928	35,174
Goodwill and Intangibles	1,814	2,814
Net Plant	4,429	10,669
Assets of Discontinued Operations	33,171	48,657
Current Liabilities	15,616	22,864
Deferred Income Taxes	5,116	4,695
Liabilities of Discontinued Operations	$ 20,732	$ 27,559

XML

Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
9.000% Notes, due December 15, 2016
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%
Long-Term Debt, Due Date	Dec. 15, 2016	Dec. 15, 2016
9.000% Notes, due December 15, 2016 | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	9.00%	9.00%
Long-Term Debt, Due Date	Dec. 15, 2016	Dec. 15, 2016
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 4.63%, due December 1, 2021 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | OTP
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018	Apr. 01, 2018
North Dakota Development Note, 3.95%, due April 1, 2018 | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018	Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | Otter Tail Corporation
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

XML

Share-Based Payments (Detail Textuals)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award	116,250
Stock Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period specified for average adjusted return	3 years
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target award total shareholder return/equity component	51,667
Targeted aggregate common shares award	77,500
Stock Performance Awards | Executive Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Executive Officers | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	0.00%
Stock Performance Awards Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target award total shareholder return/equity component	25,833

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Schedule of percent of consolidated sales revenue by country

	Three Months Ended March 31,
	2015			2014
United States of America		96.3	%		97.2	%
Mexico		3.0	%		2.2	%
Canada		0.6	%		0.5	%
All Other Countries (none individually greater than 0.05%)		0.1	%		0.1	%

Schedule of information by business segments

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	113,547		$	119,088
Manufacturing		56,759			55,435
Plastics		32,552			40,483
Intersegment Eliminations		(17	)		(40	)
Total	$	202,841		$	214,966

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Electric	$	6,121	$	5,079
Manufacturing		832		808
Plastics		246		247
Corporate and Intersegment Eliminations		544		461
Total	$	7,743	$	6,595

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	4,221		$	5,750
Manufacturing		504			1,671
Plastics		1,264			2,133
Corporate		(1,916	)		(992	)
Total	$	4,073		$	8,562

Net Income

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	13,178		$	16,653
Manufacturing		1,184			2,896
Plastics		2,120			3,460
Corporate		(2,701	)		(1,230	)
Discontinued Operations		4,154			(349	)
Total	$	17,935		$	21,430

Identifiable Assets

	March 31,			December 31,
(in thousands)		2015			2014
Electric		$	1,484,289		$	1,472,647
Manufacturing			139,143			130,701
Plastics			90,256			87,356
Corporate			68,321			51,918
Assets of Discontinued Operations			33,171			48,657
Total		$	1,815,180		$	1,791,279

XML

Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	$ 202,841		$ 214,966
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,615		2,304
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	2,557		1,763
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,928	[1]	1,521	[1]
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,883		1,435
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	1,936		1,514
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	2,156		1,522
Otter Tail Power Company | North Dakota | Big Stone II Project Costs
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders			361
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	363		346
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Revenues Recorded under Rate Riders	$ 504

[1] Includes MNCIP costs recovered in base rates.

XML

Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 6) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015
Accounting Policies [Abstract]
2015	$ 977
2016	945
2017	849
2018	849
2019	$ 849

XML

Short-Term and Long-Term Borrowings - Status of lines of credit (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Line Limit	$ 320,000
In Use	48,652
Restricted due to Outstanding Letters of Credit	755
Available	270,593	308,312
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	150,000
In Use	40,846
Restricted due to Outstanding Letters of Credit	195
Available	108,959	138,872
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	7,806
Restricted due to Outstanding Letters of Credit	560
Available	$ 161,634	$ 169,440

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Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 1) (Forward Energy Contracts, Level 3, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
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	$ (13,631)	$ (11,341)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods	3,386	1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods	(368)	3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period	(10,613)	(6,683)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period	(291)	40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$ (10,904)	$ (6,643)

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Rate and Regulatory Matters (Detail Textuals 1) (USD $)	3 Months Ended	0 Months Ended	1 Months Ended
	Mar. 31, 2015	Feb. 07, 2013 Project	Dec. 31, 2014	Jul. 30, 2014	Jul. 31, 2014	Apr. 25, 2011	Sep. 26, 2014
Conservation Improvement Program | Fiscal Year 2014
Regulatory Matters [Line Items]
Financial incentives recognized during period	$ 3,000,000
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013
Regulatory Matters [Line Items]
Financial incentive request approved							4,000,000
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 To 2015
Regulatory Matters [Line Items]
Lower Estimated Incentives	0.09
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 To 2016
Regulatory Matters [Line Items]
Lower Estimated Incentives	0.07
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider
Regulatory Matters [Line Items]
Number of additional projects approved		3
Otter Tail Power Company | Minnesota Public Utilities Commission | Environmental Cost Recovery Rider
Regulatory Matters [Line Items]
Annual revenue requirement			9,800,000	6,100,000	10,200,000
Annual increase in revenue requirement					4,100,000
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case
Regulatory Matters [Line Items]
General rate revenue increase approved						$ 5,000,000
Percentage of increase in base rate revenue approved by rate authority						1.60%
Public utilities allowed rate of return prior to approval of increase in base rate						8.33%
Public utilities allowed rate of return subsequent to approval of increase in base rate						8.61%
Public utilities allowed rate of return on equity prior to approval of increase in base rate						10.43%
Public utilities allowed rate of return on equity subsequent to approval of increase in base rate						10.74%

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Stockholders Equity Note [Line Items]
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations	$ 0.01
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS)
Stockholders Equity Note [Line Items]
Agreement To Sell Shares Value	$ 75

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Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 4) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Otter Tail Power Company
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit	$ 282		$ 45
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	11,285	[1]	13,888	[1]
Loss Contracts with No Ratings Triggers or Deposit Requirements			297
Total Current Liability - Marked-to-Market Loss	$ 11,567		$ 14,230

[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631

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Segment Information - Percent of sales revenue by country (Details) (Sales)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
United States of America
Segment Reporting Information [Line Items]
Percentage of sales revenue	96.30%	97.20%
Mexico
Segment Reporting Information [Line Items]
Percentage of sales revenue	3.00%	2.20%
Canada
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.60%	0.50%
All Other Countries (none individually greater than 0.05%)
Segment Reporting Information [Line Items]
Percentage of sales revenue	0.10%	0.10%

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Segment Information

3 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Segment Information

2. Segment Information

The Company’s businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. These businesses sell products and provide services to customers primarily in the United States. The three segments are: Electric, Manufacturing and Plastics.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is an active wholesale participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

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

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

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

No single customer accounted for over 10% of the Company’s consolidated revenues in 2014. All of the Company’s long-lived assets are within the United States.

The following table presents the percent of consolidated sales revenue by country:

	Three Months Ended March 31,
	2015			2014
United States of America		96.3	%		97.2	%
Mexico		3.0	%		2.2	%
Canada		0.6	%		0.5	%
All Other Countries (none individually greater than 0.05%)		0.1	%		0.1	%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2015 and 2014 and total assets by business segment as of March 31, 2015 and December 31, 2014 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	113,547		$	119,088
Manufacturing		56,759			55,435
Plastics		32,552			40,483
Intersegment Eliminations		(17	)		(40	)
Total	$	202,841		$	214,966

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Electric	$	6,121	$	5,079
Manufacturing		832		808
Plastics		246		247
Corporate and Intersegment Eliminations		544		461
Total	$	7,743	$	6,595

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	4,221		$	5,750
Manufacturing		504			1,671
Plastics		1,264			2,133
Corporate		(1,916	)		(992	)
Total	$	4,073		$	8,562

Net Income

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Electric	$	13,178		$	16,653
Manufacturing		1,184			2,896
Plastics		2,120			3,460
Corporate		(2,701	)		(1,230	)
Discontinued Operations		4,154			(349	)
Total	$	17,935		$	21,430

Identifiable Assets

	March 31,		December 31,
(in thousands)	2015		2014
Electric	$	1,484,289	$	1,472,647
Manufacturing		139,143		130,701
Plastics		90,256		87,356
Corporate		68,321		51,918
Assets of Discontinued Operations		33,171		48,657
Total	$	1,815,180	$	1,791,279

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Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parenthetical) (Details) (Otter Tail Power Company, USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Otter Tail Power Company
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	$ 11,285	[1]	$ 13,888	[1]
Offsetting Gains with Counterparties under Master Netting Agreements	(381)		(257)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$ 10,904		$ 13,631

[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631

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Summary of Significant Accounting Policies - Reconciliation of OTP's emission allowances (Details 7) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Intangible Assets [Line Items]
Emission Allowances Beginning Balance		$ 11,251
Emission Allowances Ending Balance	11,113	11,251
Emission Allowances
Intangible Assets [Line Items]
Emission Allowances Beginning Balance
Allowances Purchased	168
Allowances Used	(62)
Emission Allowances Ending Balance	$ 106

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2015

Stockholders Equity and Earnings Per Share [Abstract]

Schedule of reconciliation of common shareholders' equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2014	$	186,090		$	278,436		$	112,903		$	(4,663	)	$	572,766
Common Stock Issuances, Net of Expenses		1,220			6,302									7,522
Common Stock Retirements		(195	)		(1,044	)								(1,239	)
Net Income								17,935						17,935
Other Comprehensive Income											141			141
Tax Benefit – Stock Compensation					24									24
Employee Stock Incentive Plans Expense					623									623
Common Dividends ($0.3075 per share)								(11,498	)					(11,498	)
Balance, March 31, 2015	$	187,115		$	284,341		$	119,340		$	(4,522	)	$	586,274

Schedule of common shares outstanding from December 31, 2014 through March 31, 2015

Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Executive Stock Performance Awards (2012-2014 shares earned)	89,991
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	42,518
Cash Invested	16,553
At-the-Market Offering	38,160
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	5,985
Employee Stock Ownership Plan	21,137
Stock Options Exercised	9,000
Vesting of Restricted Stock Units	700
Retirements:
Shares Withheld for Individual Income Tax Requirements	(39,131	)
Common Shares Outstanding, March 31, 2015	37,422,959

Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted

	2015			2014
Weighted Average Common Shares Outstanding – Basic		37,243,118			36,240,350
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		229,100			131,000
Nonvested Restricted Shares		83,330			90,798
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		70,900			55,655
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		40,462			39,197
Potentially Dilutive Stock Options		3,750			18,050
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(169,842	)		(127,709	)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(2,937	)		(15,426	)
Total Dilutive Shares		254,763			191,565
Weighted Average Common Shares Outstanding – Diluted		37,497,881			36,431,915

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Forward Contracts Classified as Derivatives (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule for balance sheet location and fair value amounts of the company's forward energy contracts classified as derivatives

(in thousands)	March 31, 2015			December 31, 2014
Current Asset – Marked-to-Market Gain	$	381		$	257
Regulatory Asset – Current Deferred Marked-to-Market Loss		2,059			4,492
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,226			9,396
Total Assets		11,666			14,145
Current Liability – Marked-to-Market Loss		(11,285	)		(13,888	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(204	)		--
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(177	)		(257	)
Total Liabilities		(11,666	)		(14,145	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--

(in thousands)	Year-to-Date March 31, 2015		Year-to-Date March 31, 2014
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	--	$	115
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		--		(72	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--		(43	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--		--
Changes in Fair Value of Contracts Entered into in Current Period		--		39
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--	$	39

Schedule of realized and unrealized net loss on forward energy contracts

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Net Loss on Forward Electric Energy Contracts	$	--	$	(4	)

Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements

(in thousands)	March 31, 2015			December 31, 2014
Derivative assets subject to legally enforceable netting arrangements	$	381		$	257
Derivative liabilities subject to legally enforceable netting arrangements		(11,567	)		(14,230	)
Net balance subject to legally enforceable netting arrangements	$	(11,186	)	$	(13,973	)

Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions

Current Liability – Marked-to-Market Loss  (in thousands)	March 31, 2015			December 31, 2014
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	282		$	45
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,285			13,888
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			297
Total Current Liability – Marked-to-Market Loss	$	11,567		$	14,230
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	$	11,285		$	13,888
Offsetting Gains with Counterparties under Master Netting Agreements		(381	)		(257	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,904		$	13,631

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Regulatory Assets and Liabilities (Detail Textuals) (Debt Reacquisition Premiums)	3 Months Ended
	Mar. 31, 2015
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	210 months

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Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 8) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions	$ 32,838	[1]	$ 22,244	[1]
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions	$ 7,554	[2]	$ 3,434	[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.

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Share-Based Payments (Tables)

3 Months Ended

Mar. 31, 2015

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Schedule of stock incentive awards granted to the company's executive officers

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	December 31, 2017
Restricted Stock Units Granted to Executive Officers:
Graded Vesting		20,900	$	31.675	25% per year through February 6, 2019
Cliff Vesting		6,400	$	31.675	100% on February 6, 2020

Schedule of compensation expense under stock-based payment programs

	Three months ended
	March 31,
(in thousands)	2015		2014
Employee Stock Purchase Plan (15% discount)	$	49	$	42
Restricted Stock Granted to Directors		98		123
Restricted Stock Granted to Executive Officers		157		135
Restricted Stock Units Granted to Non-Executive Employees		66		58
Restricted Stock Units Granted to Executive Officers		253		--
Stock Performance Awards Granted to Executive Officers		1,020		526
Totals	$	1,643	$	884

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Short-Term and Long-Term Borrowings (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Schedule of lines of credit

(in thousands)	Line Limit		In Use on March 31, 2015		Restricted due to Outstanding Letters of Credit		Available on March 31, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
OTP Credit Agreement		170,000		7,806		560		161,634		169,440
Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312

Schedule of short-term and long-term debt outstanding

March 31, 2015 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	7,806	$	40,846	$	48,652
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		237		237
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,074		1,074
Total	$	445,000	$	53,641	$	498,641
Less: Current Maturities		--		204		204
Total Long-Term Debt	$	445,000	$	53,437	$	498,437
Total Short-Term and Long-Term Debt (with current maturities)	$	452,806	$	94,487	$	547,293

December 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	10,854	$	10,854
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330	$	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,105		1,105
Total	$	445,000	$	53,691	$	498,691
Less: Current Maturities		--		201		201
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,489	$	498,489
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. Summary of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.

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 Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (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 March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	381
Investments:
Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
Corporate Debt Securities – Held by Captive Insurance Company				6,625
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,229
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
Total Assets	$	2,550	$	7,854	$	381
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	282	$	--
Derivative Liabilities - Forward Energy Contracts						11,285
Total Liabilities	$	--	$	282	$	11,285

December 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	257
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				6,761
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,253
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
Total Assets	$	713	$	8,014	$	257
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	342	$	--
Derivative Liabilities - Forward Energy Contracts						13,888
Total Liabilities	$	--	$	342	$	13,888

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of March 31, 2015 and December 31, 2014, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The March 31, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour.

In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three month periods ended March 31, 2015 and 2014.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Forward Energy Contracts - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2015		2014
Finished Goods	$	27,607	$	27,998
Work in Process		9,894		10,628
Raw Material, Fuel and Supplies		47,014		46,577
Total Inventories	$	84,515	$	85,203

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table summarizes changes to goodwill by business segment during 2015:

(in thousands)	Gross Balance December 31, 2014		Accumulated Impairments		Balance (net of impairments) December 31, 2014		Adjustments to Goodwill in 2015			Balance (net of impairments) March 31, 2015
Manufacturing	$	12,186	$	--	$	12,186	$	--		$	12,186
Plastics		19,302		--		19,302		--			19,302
Total	$	31,488	$	--	$	31,488	$	--	$	31,488

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,996	$	10,815	57-157 months
Other Intangible Assets Including Contracts		639		447		192	18 months
Emission Allowances		106		--		106	Expensed as used
Total	$	17,556	$	6,443	$	11,113
December 31, 2014(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,784	$	11,027	60-160 months
Other Intangible Assets Including Contracts		639		415		224	21 months
Total	$	17,450	$	6,199	$	11,251

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2015		2016		2017		2018		2019
Estimated Amortization Expense – Intangible Assets	$	977	$	945	$	849	$	849	$	849

The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015:

	Three Months Ended
(in thousands)	March 31, 2015
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(62	)
Emission Allowances Ending Balance	$	106

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2015		2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	32,838	$	22,244
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554	$	3,434
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.

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2015 could be as high as $28.5 million.

New Accounting Standards

ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016,however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.

ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03),which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015.

ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements.

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Pension Plan and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2015

Pension Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	1,500		$	1,175
Interest Cost on Projected Benefit Obligation		3,325			3,285
Expected Return on Assets		(4,600	)		(4,187	)
Amortization of Prior-Service Cost:
From Regulatory Asset		47			64
From Other Comprehensive Income1		1			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,633			868
From Other Comprehensive Income1		40			23
Net Periodic Pension Cost	$	1,946		$	1,230
1Corporate cost included in Other Nonelectric Expenses.

Executive Survivor and Supplemental Retirement Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2015		2014
Service Cost—Benefit Earned During the Period	$	47	$	13
Interest Cost on Projected Benefit Obligation		381		380
Amortization of Prior-Service Cost:
From Regulatory Asset		4		5
From Other Comprehensive Income1		10		13
Amortization of Net Actuarial Loss:
From Regulatory Asset		83		35
From Other Comprehensive Income2		151		12
Net Periodic Pension Cost	$	676	$	458
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	4	$	5
Other Nonelectric Expenses		6		8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	78	$	33
Other Nonelectric Expenses		73		(21	)

Postretirement Benefits

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	375		$	315
Interest Cost on Projected Benefit Obligation		550			558
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		48			--
From Other Comprehensive Income1		1			--
Net Periodic Postretirement Benefit Cost	$	1,026		$	925
Effect of Medicare Part D Subsidy	$	(450	)	$	(308	)
1 Corporate cost included in Other Nonelectric Expenses.

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Income Tax Expense - Continuing operations effective income tax rate (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 17,854	$ 30,341
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	6,963	11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits	2,054	2,252
Section 199 Domestic Production Activities Deduction	(362)	(358)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(212)	(212)
Employee Stock Ownership Plan Dividend Deduction	(172)	(189)
AFUDC Equity	(100)	(133)
Corporate Owned Life Insurance	(80)	(112)
Other Items - Net	90	(15)
Income Tax Expense - Continuing Operations	$ 4,073	$ 8,562
Effective Income Tax Rate - Continuing Operations	22.80%	28.20%

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Summary of Significant Accounting Policies - Components of intangible assets (Details 4) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Amortizable Intangible Assets:
Gross Carrying Amount	17,556	17,450
Accumulated Amortization	6,443	6,199
Net Carrying Amount	11,113	11,251
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	16,811	16,811
Accumulated Amortization	5,996	5,784
Net Carrying Amount	10,815	11,027
Customer Relationships | Minimum
Amortizable Intangible Assets:
Amortization Periods	57 months	60 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Amortization Periods	157 months	160 months
Other Intangible Assets Including Contracts
Amortizable Intangible Assets:
Gross Carrying Amount	639	639
Accumulated Amortization	447	415
Net Carrying Amount	192	224
Amortization Periods	18 months	21 months
Emission Allowances
Amortizable Intangible Assets:
Gross Carrying Amount	106
Accumulated Amortization
Net Carrying Amount	106

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Rate and Regulatory Matters (Detail Textuals 2) (Otter Tail Power Company, North Dakota Public Service Commission, USD $)	1 Months Ended	0 Months Ended	1 Months Ended
	Aug. 29, 2014	Mar. 12, 2014	Mar. 31, 2014	Nov. 25, 2009
Big Stone II Cost Recovery
Regulatory Matters [Line Items]
Regulators jurisdictional share of transmission costs	$ 100,000
Renewable Resource Cost Recovery Rider
Regulatory Matters [Line Items]
Percentage of reduction in the NDRRA		13.50%
Environmental Cost Recovery Rider | Minimum
Regulatory Matters [Line Items]
Percentage of ECR rider rate			4.319%
Environmental Cost Recovery Rider | Maximum
Regulatory Matters [Line Items]
Percentage of ECR rider rate			7.531%
2010 General Rate Case
Regulatory Matters [Line Items]
Revenue increase approved by rate authority				$ 3,600,000
Percentage of increase in base rate revenue approved by rate authority				3.00%
Percentage Of Allowed Rate Of Return On Rate Base				8.62%
Percentage Of Allowed Rate Of Return On Equity				10.75%

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Share-Based Payments (Detail Textuals 1) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items]
Unrecognized compensation expense related to stock-based compensation	$ 2.8
Weighted-average period of amortization	2 years 3 months 18 days

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Consolidated Balance Sheets (not audited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents	$ 157
Accounts Receivable:
Trade - Net	74,071	60,172
Other	14,406	13,179
Inventories	84,515	85,203
Deferred Income Taxes	52,065	49,482
Unbilled Revenues	15,199	17,996
Regulatory Assets	20,352	25,273
Other	6,935	7,187
Assets of Discontinued Operations	33,171	48,657
Total Current Assets	300,871	307,149
Investments	10,405	8,582
Other Assets	30,900	30,111
Goodwill	31,488	31,488
Other Intangibles - Net	11,113	11,251
Deferred Debits
Unamortized Debt Expense	4,130	4,300
Regulatory Assets	127,368	129,868
Total Deferred Debits	131,498	134,168
Plant
Electric Plant in Service	1,560,459	1,545,112
Nonelectric Operations	178,289	175,159
Construction Work in Progress	269,999	248,677
Total Gross Plant	2,008,747	1,968,948
Less Accumulated Depreciation and Amortization	709,842	700,418
Net Plant	1,298,905	1,268,530
Total Assets	1,815,180	1,791,279
Current Liabilities
Short-Term Debt	48,652	10,854
Current Maturities of Long-Term Debt	204	201
Accounts Payable	95,876	107,013
Accrued Salaries and Wages	12,826	19,256
Accrued Taxes	15,342	13,793
Derivative Liabilities	11,567	14,230
Other Accrued Liabilities	8,890	8,793
Liabilities of Discontinued Operations	20,732	27,559
Total Current Liabilities	214,089	201,699
Pensions Benefit Liability	93,084	102,711
Other Postretirement Benefits Liability	54,100	53,638
Other Noncurrent Liabilities	24,485	26,794
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	239,999	230,810
Deferred Tax Credits	25,914	26,384
Regulatory Liabilities	77,851	77,013
Other	947	975
Total Deferred Credits	344,711	335,182
Capitalization
Long-Term Debt, Net of Current Maturities	498,437	498,489
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2015-37,422,959 Shares; 2014 - 37,218,053 Shares	187,115	186,090
Premium on Common Shares	284,341	278,436
Retained Earnings	119,340	112,903
Accumulated Other Comprehensive Loss	(4,522)	(4,663)
Total Common Equity	586,274	572,766
Total Capitalization	1,084,711	1,071,255
Total Liabilities and Equity	1,815,180	1,791,279
Cumulative Preferred Shares
Capitalization
Cumulative Shares
Cumulative Preference Shares
Capitalization
Cumulative Shares

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Summary of Significant Accounting Policies (Detail Textuals) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Minimum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	1 year
Maximum
Significant Accounting Policies [Line Items]
Product warranty period (in years)	15 years
Forward Electricity Contracts | Level 3
Significant Accounting Policies [Line Items]
Electric inputs minimum deviation below active trade hub prices per megawatt-hour	2.46
Electric inputs maximum deviation below active trading hub price per megawatt-hour	8.00
Electric inputs weighted average price per megawatt-hour	34.45
Forward Electricity Contracts | Power purchase contracts | Level 3
Significant Accounting Policies [Line Items]
Percentage of offset by regulatory liabilities and assets of fuel clause adjustment treatment of fuel costs	100.00%
Net impact of recorded fair valuation gains or losses related to derivative contract	0
Net income impact of future fair valuation adjustments of contracts	0

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Consolidated Statements of Comprehensive Income (not audited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 17,935	$ 21,430
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	(3)	(17)
Gains (Losses) Arising During Period	32	(17)
Income Tax (Expense) Benefit	(10)	12
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	19	(22)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	204	50
Income Tax (Expense)	(82)	(20)
Pension and Postretirement Benefit Plans - net-of-tax	122	30
Total Other Comprehensive Income	141	8
Total Comprehensive Income	$ 18,076	$ 21,438

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Forward Contracts Classified as Derivatives - Realized and unrealized net (losses)/gains on forward energy contracts included in electric operating revenues (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Loss on Forward Electric Energy Contracts		$ (4)

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations

	For the Three Months Ended March 31,
(in thousands)	2015			2014
Operating Revenues	$	18,724		$	25,506
Operating Expenses		22,141			26,368
Goodwill Impairment Charge		1,000			--
Operating Loss		(4,417	)		(862	)
Other (Deductions) Income		(31	)		288
Income Tax Benefit		(1,376	)		(225	)
Net Loss from Operations		(3,072	)		(349	)
Gain on Disposition Before Taxes		12,042			--
Income Tax Expense on Disposition		4,816			--
Net Gain on Disposition		7,226			--
Net Income (Loss)	$	4,154		$	(349	)

(in thousands)	March 31, 2015		December 31, 2014
Current Assets	$	26,928	$	35,174
Goodwill and Intangibles		1,814		2,814
Net Plant		4,429		10,669
Assets of Discontinued Operations	$	33,171	$	48,657
Current Liabilities	$	15,616	$	22,864
Deferred Income Taxes		5,116		4,695
Liabilities of Discontinued Operations	$	20,732	$	27,559

Schedule of costs incurred and billings and estimated earnings

	March 31,			December 31,
(in thousands)	2015			2014
Costs Incurred on Uncompleted Contracts	$	339,594		$	402,332
Less Billings to Date		(354,256	)		(411,909	)
Plus Estimated Earnings Recognized		14,458			15,154
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

Schedule of costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings

	March 31,			December 31,
(in thousands)	2015			2014
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,216		$	8,133
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(3,420	)		(2,556	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

Schedule of warranty reserves

(in thousands)	2015			2014
Warranty Reserve Balance, January 1	$	2,527		$	3,087
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(6	)		--
Decrease in Warranty Estimates for Prior Years		--			(100	)
Warranty Reserve Balance, March 31	$	2,521		$	2,987

Schedule of accounts receivable retained by customers pending project completion

	March 31,		December 31,
(in thousands)	2015		2014
Accounts Receivable Retained by Customers	$	4,018	$	6,759

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1)	3 Months Ended
	Mar. 31, 2015
Stockholders Equity and Earnings Per Share [Abstract]
Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Executive Stock Performance Awards (2012-2014 shares earned)	89,991
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	42,518
Cash Invested	16,553
At-the-Market Offering	38,160
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	5,985
Employee Stock Ownership Plan	21,137
Stock Options Exercised	9,000
Vesting of Restricted Stock Units	700
Retirements:
Shares Withheld for Individual Income Tax Requirements	(39,131)
Common Shares Outstanding, March 31, 2015	37,422,959

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Subsequent Events

3 Months Ended

Mar. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

17. Subsequent Events

Sale of Foley

On April 30, 2015 the Company completed the sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. Although the net carrying value of Foley had been adjusted to its indicated fair value through goodwill impairment charges recorded prior to the sale based on acceptance of the buyer’s offering price, the final proceeds and loss on sale will not be known until the adjustments for working capital and other related items have been determined.

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Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Level 1
Assets:
Total Assets	$ 2,550	$ 713
Liabilities:
Total Liabilities
Level 1 | Forward Energy Contracts
Assets:
Derivative Assets
Level 1 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale	2,000
Level 1 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities
Level 1 | Money Market and Mutual Funds
Assets:
Derivative Assets		120
Other Assets - Nonqualified Retirement Savings Plan	550	593
Level 2
Assets:
Total Assets	7,854	8,014
Liabilities:
Total Liabilities	282	342
Level 2 | Forward Energy Contracts
Assets:
Derivative Assets
Level 2 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale
Level 2 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities	282	342
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	6,625	6,761
Level 2 | U.S. Government-Sponsored Enterprises' Debt Securities
Assets:
Investments - Held by Captive Insurance Company	1,229	1,253
Level 3
Assets:
Total Assets	381	257
Liabilities:
Total Liabilities	11,285	13,888
Level 3 | Forward Energy Contracts
Assets:
Derivative Assets	381	257
Liabilities:
Derivative Liabilities	11,285	13,888
Level 3 | Money Market Deposit Escrow
Assets:
Money Market Deposit Escrow Account - AEV, Inc. Sale
Level 3 | Forward Gasoline Purchase Contracts
Liabilities:
Derivative Liabilities

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Schedule of assets and liabilities that are measured at fair value on a recurring basis

March 31, 2015 (in thousands)	Level 1			Level 2			Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--		$	--		$	381
Investments:
Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
Corporate Debt Securities – Held by Captive Insurance Company					6,625
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company					1,229
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
Total Assets	$	2,550		$	7,854		$	381
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	--		$	282		$	--
Derivative Liabilities - Forward Energy Contracts								11,285
Total Liabilities	$	--		$	282		$	11,285

December 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	257
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				6,761
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,253
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
Total Assets	$	713	$	8,014	$	257
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	342	$	--
Derivative Liabilities - Forward Energy Contracts						13,888
Total Liabilities	$	--	$	342	$	13,888

Schedule of derivative asset and liability fair valuations

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Forward Energy Contracts - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)

Schedule of inventories

	March 31,		December 31,
(in thousands)	2015		2014
Finished Goods	$	27,607	$	27,998
Work in Process		9,894		10,628
Raw Material, Fuel and Supplies		47,014		46,577
Total Inventories	$	84,515	$	85,203

Schedule of changes to goodwill by business segment

(in thousands)	Gross Balance December 31, 2014		Accumulated Impairments		Balance (net of impairments) December 31, 2014		Adjustments to Goodwill in 2015		Balance (net of impairments) March 31, 2015
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Total	$	31,488	$	--	$	31,488	$	--	$	31,488

Schedule of components of intangible assets

March 31, 2015 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,996	$	10,815	57-157 months
Other Intangible Assets Including Contracts		639		447		192	18 months
Emission Allowances		106		--		106	Expensed as used
Total	$	17,556	$	6,443	$	11,113
December 31, 2014(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,784	$	11,027	60-160 months
Other Intangible Assets Including Contracts		639		415		224	21 months
Total	$	17,450	$	6,199	$	11,251

Schedule of amortization expense for intangible assets

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2015		2016		2017		2018		2019
Estimated Amortization Expense – Intangible Assets	$	977	$	945	$	849	$	849	$	849

Schedule of reconciliation of OTP's emission allowances

	Three Months Ended
(in thousands)	March 31, 2015
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(62	)
Emission Allowances Ending Balance	$	106

Schedule of supplemental disclosure of cash flow information

	As of March 31,
(in thousands)	2015		2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	32,838	$	22,244
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554	$	3,434
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.

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Share-Based Payments - Stock Incentive Awards (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	116,250
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	77,500
Weighted Average Grant-Date Fair Value per Award	26.99
Vesting Date	December 31, 2017
Restricted Stock Units | Executive Officer Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	20,900
Weighted Average Grant-Date Fair Value per Award	31.675
Vesting Percentage	25.00%
Vesting Date	February 6, 2019
Restricted Stock Units | Executive Officer Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted	6,400
Weighted Average Grant-Date Fair Value per Award	31.675
Vesting Percentage	100.00%
Vesting Date	February 6, 2020

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Consolidated Statements of Cash Flows (not audited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash Flows from Operating Activities
Net Income	$ 17,935	$ 21,430
Adjustments to Reconcile Net Income to Net Cash Used in Operating Activities:
Net Gain from Sale of Discontinued Operations	(7,226)
Net Loss from Discontinued Operations	3,072	349
Depreciation and Amortization	14,535	14,267
Deferred Tax Credits	(470)	(454)
Deferred Income Taxes	7,038	13,073
Change in Deferred Debits and Other Assets	3,538	(888)
Discretionary Contribution to Pension Plan	(10,000)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	41	(2,408)
Allowance for Equity/Other Funds Used During Construction	(256)	(340)
Change in Derivatives Net of Regulatory Deferral	(59)	118
Stock Compensation Expense - Equity Awards	623	358
Other - Net	206	182
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(11,288)	(22,329)
Change in Inventories	688	(9,236)
Change in Other Current Assets	1,270	437
Change in Payables and Other Current Liabilities	(20,185)	(7,731)
Change in Interest and Income Taxes Receivable/Payable	(1,549)	1,013
Net Cash Used in Continuing Operations	(2,087)	(12,159)
Net Cash Used in Discontinued Operations	(6,263)	(6,898)
Net Cash Used in Operating Activities	(8,350)	(19,057)
Cash Flows from Investing Activities
Capital Expenditures	(35,738)	(37,311)
Net Proceeds from Disposal of Noncurrent Assets	1,292	848
Net Increase in Other Investments	(3,492)	(989)
Net Cash Used in Investing Activities - Continuing Operations	(37,938)	(37,452)
Net Proceeds from Sale of Discontinued Operations	21,343
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations	(1,759)	285
Net Cash Used in Investing Activities	(18,354)	(37,167)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(1,236)
Net Short-Term Borrowings (Repayments)	37,798	(39,296)
Proceeds from Issuance of Common Stock - net of Issuance Expenses	4,697	3,666
Payments for Retirement of Capital Stock	(1,239)	(242)
Proceeds from Issuance of Long-Term Debt		150,000
Short-Term and Long-Term Debt Issuance Expenses	(4)	(502)
Payments for Retirement of Long-Term Debt	(49)	(40,946)
Dividends Paid and Other Distributions	(11,498)	(10,993)
Net Cash Provided by Financing Activities - Continuing Operations	28,469	61,687
Net Cash Used in Financing Activities - Discontinued Operations	(1,178)
Net Cash Provided by Financing Activities	27,291	61,687
Net Change in Cash and Cash Equivalents - Discontinued Operations	(430)	(126)
Net Change in Cash and Cash Equivalents	157	5,337
Cash and Cash Equivalents at Beginning of Period		2,007
Cash and Cash Equivalents at End of Period	$ 157	$ 7,344

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Consolidated Balance Sheets (not audited) (Parentheticals) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	37,422,959	37,218,053
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding
Cumulative Preference Shares
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)
Cumulative shares, outstanding

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Short-Term and Long-Term Borrowings

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Short-Term and Long-Term Borrowings

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of March 31, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on March 31, 2015		Restricted due to Outstanding Letters of Credit		Available on March 31, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	40,846	$	195	$	108,959	$	138,872
OTP Credit Agreement		170,000		7,806		560		161,634		169,440
Total	$	320,000	$	48,652	$	755	$	270,593	$	308,312

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	7,806	$	40,846	$	48,652
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330		52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017		33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		237		237
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,074		1,074
Total	$	445,000	$	53,641	$	498,641
Less: Current Maturities		--		204		204
Total Long-Term Debt	$	445,000	$	53,437	$	498,437
Total Short-Term and Long-Term Debt (with current maturities)	$	452,806	$	94,487	$	547,293

December 31, 2014 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	--	$	10,854	$	10,854
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330	$	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018		--		256		256
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021		--		1,105		1,105
Total	$	445,000	$	53,691	$	498,691
Less: Current Maturities		--		201		201
Unamortized Debt Discount		--		1		1
Total Long-Term Debt	$	445,000	$	53,489	$	498,489
Total Short-Term and Long-Term Debt (with current maturities)	$	445,000	$	64,544	$	509,544

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Subsequent Events (Detail Textuals) (Subsequent event, Foley, USD $)
In Millions, unless otherwise specified

3 Months Ended

Apr. 30, 2015

Subsequent event | Foley

Subsequent Event [Line Items]

Proceeds from sale of Aevenia before working capital and other adjustments

$ 12.0

Consideration for sale of business, description

The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing.

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Discontinued Operations - Accounts receivable retained by customers pending project completion (Details 5) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Accounts Receivable Retained by Customers	$ 4,018	$ 6,759

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Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
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 Common Stock Shares Outstanding		37,483,725
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

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Pension Plan and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Pension Plan and Other Postretirement Benefits

11. Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company’s noncontributory funded pension plan are as follows:

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	1,500		$	1,175
Interest Cost on Projected Benefit Obligation		3,325			3,285
Expected Return on Assets		(4,600	)		(4,187	)
Amortization of Prior-Service Cost:
From Regulatory Asset		47			64
From Other Comprehensive Income1		1			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,633			868
From Other Comprehensive Income1		40			23
Net Periodic Pension Cost	$	1,946		$	1,230
1Corporate cost included in Other Nonelectric Expenses.

Cash flows—The Company made discretionary plan contributions totaling $10,000,000 in January 2015. The Company currently is not required and does not expect to make an additional contribution to the plan in 2015. The Company also made discretionary plan contributions totaling $20,000,000 in January 2014.

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three Months Ended March 31,
(in thousands)	2015		2014
Service Cost—Benefit Earned During the Period	$	47	$	13
Interest Cost on Projected Benefit Obligation		381		380
Amortization of Prior-Service Cost:
From Regulatory Asset		4		5
From Other Comprehensive Income1		10		13
Amortization of Net Actuarial Loss:
From Regulatory Asset		83		35
From Other Comprehensive Income2		151		12
Net Periodic Pension Cost	$	676	$	458
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	4	$	5
Other Nonelectric Expenses		6		8
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	78	$	33
Other Nonelectric Expenses		73		(21	)

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

	Three Months Ended March 31,
(in thousands)	2015			2014
Service Cost—Benefit Earned During the Period	$	375		$	315
Interest Cost on Projected Benefit Obligation		550			558
Amortization of Prior-Service Cost:
From Regulatory Asset		51			51
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		48			--
From Other Comprehensive Income1		1			--
Net Periodic Postretirement Benefit Cost	$	1,026		$	925
Effect of Medicare Part D Subsidy	$	(450	)	$	(308	)
1 Corporate cost included in Other Nonelectric Expenses.

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Pension Plan and Other Postretirement Benefits (Detail Textuals) (Pension Plan, USD $)	1 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discretionary plan contributions	$ 10,000,000	$ 20,000,000

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Discontinued Operations - Warranty Reserves (Details 4) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Warranty Reserve Balance, January 1	$ 2,527	$ 3,087
Additional Provision for Warranties Made During the Year
Settlements Made During the Year	(6)
Decrease in Warranty Estimates for Prior Years		(100)
Warranty Reserve Balance, March 31	$ 2,521	$ 2,987

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Consolidated Statements of Income (not audited) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating Revenues
Electric	$ 113,533	$ 119,048
Product Sales	89,308	95,918
Total Operating Revenues	202,841	214,966
Operating Expenses
Production Fuel - Electric	14,599	22,030
Purchased Power - Electric System Use	23,692	21,785
Electric Operation and Maintenance Expenses	37,527	34,622
Cost of Products Sold (depreciation included below)	71,498	73,939
Other Nonelectric Expenses	12,463	9,951
Depreciation and Amortization	14,535	14,267
Property Taxes - Electric	3,502	2,971
Total Operating Expenses	177,816	179,565
Operating Income	25,025	35,401
Interest Charges	7,743	6,595
Other Income	572	1,535
Income Before Income Taxes - Continuing Operations	17,854	30,341
Income Tax Expense - Continuing Operations	4,073	8,562
Net Income from Continuing Operations	13,781	21,779
Discontinued Operations
Loss - net of Income Tax Benefit of $1,376 and $225 for the respective periods	(2,072)	(349)
Impairment Loss - net of Income Tax Benefit of $0 for the three months ended March 31, 2015	(1,000)
Gain on Disposition - net of Income Tax Expense of $4,816 for the three months ended March 31, 2015	7,226
Net Income (Loss) from Discontinued Operations	4,154	(349)
Net Income	$ 17,935	$ 21,430
Average Number of Common Shares Outstanding-Basic (in shares)	37,243,118	36,240,350
Average Number of Common Shares Outstanding-Diluted (in shares)	37,497,881	36,431,915
Basic Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$ 0.37	$ 0.60
Discontinued Operations (in dollars per share)	$ 0.11	$ (0.01)
Earnings Per Share, Basic, Total (in dollars per share)	$ 0.48	$ 0.59
Diluted Earnings (Loss) Per Common Share:
Continuing Operations (in dollars per share)	$ 0.37	$ 0.60
Discontinued Operations (in dollars per share)	$ 0.11	$ (0.01)
Earnings Per Share, Diluted, Total (in dollars per share)	$ 0.48	$ 0.59
Dividends Declared Per Common Share (in dollars per share)	$ 0.3075	$ 0.3025

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Forward Contracts Classified as Derivatives

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Forward Contracts Classified as Derivatives

5. Forward Contracts Classified as Derivatives

Electricity Contracts

All of OTP’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. OTP’s objective in entering into forward contracts for the purchase and sale of energy is to meet the energy requirements of its retail customers and to optimize the use of its generating and transmission facilities. OTP’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. Prior to December 2014, OTP also entered into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales. Effective December 31, 2014 OTP discontinued its trading activities not directly associated with serving retail customers.

OTP’s forward contracts outstanding as of March 31, 2015 and December 31, 2014 for the purchase of electricity are scheduled for delivery at the OTP node, which is an illiquid trading point. Prices used to value OTP’s forward purchases at this trading point were based on a basis spread between the OTP node and more liquid trading hub prices. These basis spreads were determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into Level 3 of the fair value hierarchy set forth in ASC 820.

The following tables show the effect of marking to market OTP’s forward contracts for the purchase of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of March 31, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to March 31, 2015 and December 31, 2013 to March 31, 2014:

(in thousands)	March 31, 2015			December 31, 2014
Current Asset – Marked-to-Market Gain	$	381		$	257
Regulatory Asset – Current Deferred Marked-to-Market Loss		2,059			4,492
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		9,226			9,396
Total Assets		11,666			14,145
Current Liability – Marked-to-Market Loss		(11,285	)		(13,888	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		(204	)		--
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		(177	)		(257	)
Total Liabilities		(11,666	)		(14,145	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--

(in thousands)	Year-to-Date March 31, 2015		Year-to-Date March 31, 2014
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year	$	--	$	115
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		--		(72	)
Changes in Fair Value of Contracts Entered into in Prior Periods		--		(43	)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period		--		--
Changes in Fair Value of Contracts Entered into in Current Period		--		39
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--	$	39

The following realized and unrealized net loss on forward energy contracts is included in electric operating revenues on the Company’s consolidated statements of income:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Net Loss on Forward Electric Energy Contracts	$	--	$	(4	)

OTP has established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at March 31, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.

Individual counterparty exposures for certain contracts can be offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of March 31, 2015 and December 31, 2014 are indicated in the following table:

(in thousands)	March 31, 2015			December 31, 2014
Derivative assets subject to legally enforceable netting arrangements	$	381		$	257
Derivative liabilities subject to legally enforceable netting arrangements		(11,567	)		(14,230	)
Net balance subject to legally enforceable netting arrangements	$	(11,186	)	$	(13,973	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of March 31, 2015 and December 31, 2014:

Current Liability – Marked-to-Market Loss  (in thousands)	March 31, 2015			December 31, 2014
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	282		$	45
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		11,285			13,888
Loss Contracts with No Ratings Triggers or Deposit Requirements		--			297
Total Current Liability – Marked-to-Market Loss	$	11,567		$	14,230
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	$	11,285		$	13,888
Offsetting Gains with Counterparties under Master Netting Agreements		(381	)		(257	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	10,904		$	13,631

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations (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:

	March 31, 2015						Remaining  Recovery/  Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,465	$	99,659	$	107,124	see below
Deferred Marked-to-Market Losses1		2,059		9,226		11,285	69 months
Conservation Improvement Program Costs and Incentives2		3,815		3,511		7,326	27 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,305		5,305	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		2,152		1,835		3,987	12 months
Big Stone II Unrecovered Project Costs – Minnesota1		601		3,086		3,687	93 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,140		636		2,776	24 months
Debt Reacquisition Premiums1		351		1,802		2,153	210 months
Deferred Income Taxes1		--		1,461		1,461	asset lives
Recoverable Fuel and Purchased Power Costs1		1,249		--		1,249	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		718		818	98 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		420		--		420	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
North Dakota Renewable Resource Rider Accrued Revenues2		--		61		61	12 months
Total Regulatory Assets	$	20,352	$	127,368	$	147,720
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,220	$	75,220	asset lives
North Dakota Renewable Resource Rider Accrued Refund		1,803		--		1,803	12 months
Deferred Income Taxes		--		1,447		1,447	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		908		908	see below
Minnesota Environmental Cost Recovery Rider Accrued Refund		451		--		451	12 months
Deferred Marked-to-Market Gains		204		177		381	58 months
Big Stone II Over Recovered Project Costs – North Dakota		111		--		111	9 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		99		105	225 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		86		--		86	12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		35		--		35	12 months
Total Regulatory Liabilities	$	2,744	$	77,851	$	80,595
Net Regulatory Asset Position	$	17,608	$	49,517	$	67,125
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.

	December 31, 2014						Remaining  Recovery/  Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see below
Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		943		2,455		3,398	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
Debt Reacquisition Premiums1		351		1,890		2,241	213 months
Deferred Income Taxes1		--		2,086		2,086	asset lives
Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		859		--		859	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
Total Regulatory Assets	$	25,273	$	129,868	$	155,141
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
Deferred Income Taxes		--		1,550		1,550	asset lives
North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see below
Deferred Marked-to-Market Gains		--		257		257	67 months
Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
Net Regulatory Asset Position	$	24,115	$	52,855	$	76,970
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 March 31, 2015 are related to forward purchases of energy scheduled for delivery through December 2020.

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

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

Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 2015.

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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 210 months.

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

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

North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of March 31, 2015.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2015.

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

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2015.

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

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS projectthat are refundable to Minnesota customers as of March 31, 2015.

Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of the North Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2015.

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2015.

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investment in the Big Stone Plant AQCS projectthat are refundable to North Dakota customers as of March 31, 2015.

If for any reason, OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Revenue Recognition

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, and the price is fixed or determinable. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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.

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 Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements.

Fair Value Measurements

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (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 March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	381
Investments:
Money Market Deposit Escrow Account – AEV, Inc. Sale		2,000
Corporate Debt Securities – Held by Captive Insurance Company				6,625
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,229
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		550
Total Assets	$	2,550	$	7,854	$	381
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	282	$	--
Derivative Liabilities - Forward Energy Contracts						11,285
Total Liabilities	$	--	$	282	$	11,285

December 31, 2014 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Forward Energy Contracts	$	--	$	--	$	257
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		120
Investments:
Corporate Debt Securities – Held by Captive Insurance Company				6,761
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,253
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		593
Total Assets	$	713	$	8,014	$	257
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts	$	--	$	342	$	--
Derivative Liabilities - Forward Energy Contracts					13,888
Total Liabilities	$	--	$	342	$	13,888

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods.

Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of March 31, 2015 and December 31, 2014, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The March 31, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour.

In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three month periods ended March 31, 2015 and 2014.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended
	March 31,
(in thousands)	2015			2014
Forward Energy Contracts  - Fair Values Beginning of Period	$	(13,631	)	$	(11,341	)
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods		3,386			1,160
Net Changes in Fair Value of Contracts Entered into in Prior Periods		(368	)		3,498
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(10,613	)		(6,683	)
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period		(291	)		40
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(10,904	)	$	(6,643	)

Inventories

Inventories

Inventories consist of the following:

	March 31,		December 31,
(in thousands)	2015		2014
Finished Goods	$	27,607	$	27,998
Work in Process		9,894		10,628
Raw Material, Fuel and Supplies		47,014		46,577
Total Inventories	$	84,515	$	85,203

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table summarizes changes to goodwill by business segment during 2015:

(in thousands)	Gross Balance December 31, 2014		Accumulated Impairments		Balance (net of impairments) December 31, 2014		Adjustments to Goodwill in 2015		Balance (net of impairments) March 31, 2015
Manufacturing	$	12,186	$	--	$	12,186	$	--	$	12,186
Plastics		19,302		--		19,302		--		19,302
Total	$	31,488	$	--	$	31,488	$	--	$	31,488

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014:

March 31, 2015 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,996	$	10,815	57-157 months
Other Intangible Assets Including Contracts		639		447		192	18 months
Emission Allowances		106		--		106	Expensed as used
Total	$	17,556	$	6,443	$	11,113
December 31, 2014(in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	16,811	$	5,784	$	11,027	60-160 months
Other Intangible Assets Including Contracts		639		415		224	21 months
Total	$	17,450	$	6,199	$	11,251

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2015		2014
Amortization Expense – Intangible Assets	$	244	$	244

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

(in thousands)	2015		2016		2017		2018		2019
Estimated Amortization Expense – Intangible Assets	$	977	$	945	$	849	$	849	$	849

The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015:

	Three Months Ended
(in thousands)	March 31, 2015
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(62	)
Emission Allowances Ending Balance	$	106

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2015		2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions1	$	32,838	$	22,244
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2	$	7,554	$	3,434
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.

Coyote Station Lignite Supply Agreement - Variable Interest Entity

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2015 could be as high as $28.5 million.

New Accounting Standards

New Accounting Standards

ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016,however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options.

ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03),which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015.

ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements.

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

12. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 2015 and December 31, 2014 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.

Long-Term Debt including Current Maturities—The fair value of the Company’s and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

	March 31, 2015						December 31, 2014
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	157		$	157		$	--		$	--
Short-Term Debt		(48,652	)		(48,652	)		(10,854	)		(10,854	)
Long-Term Debt including Current Maturities		(498,641	)		(571,801	)		(498,690	)		(600,828	)

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Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%

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Retained Earnings Restriction

3 Months Ended

Mar. 31, 2015

Retained Earnings Restrictions [Abstract]

Retained Earnings Restriction

8. Retained Earnings Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends 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 March 31, 2015 the Company was in compliance with the debt covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2014 for further information on the covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 45.0% and 55.0%. OTP’s equity to total capitalization ratio including short-term debt was 50.7% as of March 31, 2015. Total capitalization for OTP cannot currently exceed $987 million.

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Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 3) (Legally enforceable netting arrangements, USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Legally enforceable netting arrangements
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Derivative assets subject to legally enforceable netting arrangements	$ 381	$ 257
Derivative liabilities subject to legally enforceable netting arrangements	(11,567)	(14,230)
Net balance subject to legally enforceable netting arrangements	$ (11,186)	$ (13,973)

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

3 Months Ended

Mar. 31, 2015

Stockholders Equity and Earnings Per Share [Abstract]

Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

6. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share

Reconciliation of Common Shareholders’ Equity

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2014	$	186,090		$	278,436		$	112,903		$	(4,663	)	$	572,766
Common Stock Issuances, Net of Expenses		1,220			6,302									7,522
Common Stock Retirements		(195	)		(1,044	)								(1,239	)
Net Income								17,935						17,935
Other Comprehensive Income											141			141
Tax Benefit – Stock Compensation					24									24
Employee Stock Incentive Plans Expense					623									623
Common Dividends ($0.3075 per share)								(11,498	)					(11,498	)
Balance, March 31, 2015	$	187,115		$	284,341		$	119,340		$	(4,522	)	$	586,274

Shelf Registration

The Company’s shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 11, 2012, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 10, 2015. On May 14, 2012, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2014 through March 31, 2015:

Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Executive Stock Performance Awards (2012-2014 shares earned)	89,991
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	42,518
Cash Invested	16,553
At-the-Market Offering	38,160
Employee Stock Purchase Plan:
Cash Invested	19,993
Dividends Reinvested	5,985
Employee Stock Ownership Plan	21,137
Stock Options Exercised	9,000
Vesting of Restricted Stock Units	700
Retirements:
Shares Withheld for Individual Income Tax Requirements	(39,131	)
Common Shares Outstanding, March 31, 2015	37,422,959

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 2015 and 2014. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation of Weighted Average Common Shares Outstanding – Basic to Weighted Average Common Shares Outstanding – Diluted for the three month periods ended March 31:

	2015			2014
Weighted Average Common Shares Outstanding – Basic		37,243,118			36,240,350
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		229,100			131,000
Nonvested Restricted Shares		83,330			90,798
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		70,900			55,655
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		40,462			39,197
Potentially Dilutive Stock Options		3,750			18,050
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(169,842	)		(127,709	)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		(2,937	)		(15,426	)
Total Dilutive Shares		254,763			191,565
Weighted Average Common Shares Outstanding – Diluted		37,497,881			36,431,915

The effect of dilutive shares on earnings per share for the three month periods ended March 31, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

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Share-Based Payments

3 Months Ended

Mar. 31, 2015

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Share-Based Payments

7. Share-Based Payments

Stock Incentive Awards

On February 6, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s executive officers under the 2014 Stock Incentive Plan.

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Stock Performance Awards Granted to Executive Officers		77,500	$	26.99	December 31, 2017
Restricted Stock Units Granted to Executive Officers:
Graded Vesting		20,900	$	31.675	25% per year through February 6, 2019
Cliff Vesting		6,400	$	31.675	100% on February 6, 2020

Under the performance share awards the aggregate award for performance at target is 77,500 shares. For target performance the Company’s executive officers would earn an aggregate of 51,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2015 through December 31, 2017. The Company’s executive officers would also earn an aggregate of 25,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 116,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC Topic 718, Compensation–Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date.

Under the 2015 performance award agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to executive employment agreements with the Company is to be made at target at the date of any such event.

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement or, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.

As of March 31, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $2.8 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2015 and 2014 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2015		2014
Employee Stock Purchase Plan (15% discount)	$	49	$	42
Restricted Stock Granted to Directors		98		123
Restricted Stock Granted to Executive Officers		157		135
Restricted Stock Units Granted to Non-Executive Employees		66		58
Restricted Stock Units Granted to Executive Officers		253		--
Stock Performance Awards Granted to Executive Officers		1,020		526
Totals	$	1,643	$	884

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2014 OTP had commitments under contracts in connection with construction programs extending into 2018 of approximately $106.6 million. At March 31, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $106.1 million.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2039. In the first quarter of 2015, OTP entered into an energy purchase agreement for the purchase of electricity in April, May and June of 2015 to make up for reduced generation from Coyote Station as it continues to make repairs related to damage caused by a boiler feed pump failure and ensuing fire in December 2014. The total cost for the replacement power will be approximately $2.9 million.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2015, 2016, 2017 and 2040. In the first quarter of 2015, OTP entered into a second contract for the purchase of Wyoming subbituminous coal to meet a portion of its 2015 through 2017 coal requirements at Big Stone Plant. OTP’s share of the purchase commitment under this contract as of March 31, 2015 is approximately $10.0 million. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs.

Operating Leases

In April of 2015, OTP entered into an agreement to extend the term of its lease of rail cars used for the transport of coal to Hoot Lake Plant by 36 months beginning April 1, 2015, for a total commitment of approximately $2.8 million.

Contingencies

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $5.0 million.

In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.

On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes. Under the other proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for nonhazardous solid wastes. On December 19, 2014 the EPA announced a final rule following the Subtitle D nonhazardous provisions. Publication of the final rule on April 17, 2015 opened a 90-day window within which petitions for judicial review may be filed in the D.C. Circuit. Challenges by environmental groups are possible and the outcome of such challenges cannot be predicted. Thus, uncertainty regarding the status of this rule is likely to continue for a period of time. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. The cost impact of this rule will not be known until those actions are completed. As of the date of this report on From 10-Q, OTP had not completed its assessment under the final rule nor made a determination if compliance with the rule would require immediate remediation or result in the recognition of additional AROs beyond those already recognized by OTP in connection with its active and inactive ash disposal sites.  Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. The EPA is also considering future regulation of coal ash under Subtitle C.

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 March 31, 2015 will not be material.

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$ 0.3075	$ 0.3025

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Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Balance on January 1	$ 222	$ 4,239
Increases Related to Tax Positions for Prior Years		137
Increases Related to Tax Positions for Current Year	44
Uncertain Positions Resolved During Year
Balance on March 31	$ 266	$ 4,376

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted (Details 2)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	37,243,118	36,240,350
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers	229,100	131,000
Nonvested Restricted Shares	83,330	90,798
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	70,900	55,655
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	40,462	39,197
Potentially Dilutive Stock Options	3,750	18,050
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares	(169,842)	(127,709)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options	(2,937)	(15,426)
Total Dilutive Shares	254,763	191,565
Weighted Average Common Shares Outstanding - Diluted	37,497,881	36,431,915

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	$ 572,766
Common Stock Issuances, Net of Expenses	7,522
Common Stock Retirements	(1,239)
Net Income	17,935	21,430
Other Comprehensive Income	141
Tax Benefit - Stock Compensation	24
Employee Stock Incentive Plans Expense	623
Common Dividends ($0.3075 per share)	(11,498)
Balance, End of Period	586,274
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	186,090
Common Stock Issuances, Net of Expenses	1,220
Common Stock Retirements	(195)
Balance, End of Period	187,115
Premium On Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	278,436
Common Stock Issuances, Net of Expenses	6,302
Common Stock Retirements	(1,044)
Tax Benefit - Stock Compensation	24
Employee Stock Incentive Plans Expense	623
Balance, End of Period	284,341
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	112,903
Net Income	17,935
Common Dividends ($0.3075 per share)	(11,498)
Balance, End of Period	119,340
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, Beginning of Period	(4,663)
Other Comprehensive Income	141
Balance, End of Period	$ (4,522)

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Discontinued Operations (Detail Textuals) (USD $)

3 Months Ended

1 Months Ended

3 Months Ended

Mar. 31, 2015

Feb. 28, 2015

Dec. 31, 2014

Apr. 30, 2015

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

Proceeds from sale of discontinued operations

$ 21,343,000

Net Gain on Disposition

7,226,000

AEV, Inc.

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

Proceeds from sale of discontinued operations

22,300,000

Amount of working capital

900,000

Net Gain on Disposition

7,200,000

Foley

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

Asset Impairment Charges

1,000,000

5,600,000

Cost estimates pretax charges

2,300,000

Foley | Subsequent event

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

Proceeds from sale of Aevenia before working capital and other adjustments

$ 12,000,000

Consideration for sale of business, description

The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing.

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Income Tax Expense - Continuing Operations (Tables)

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of income from continuing operations before income taxes and income tax expense

	Three Months Ended March 31,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,054	)		(2,252	)
Section 199 Domestic Production Activities Deduction		(362	)		(358	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
AFUDC Equity		(100	)		(133	)
Corporate Owned Life Insurance		(80	)		(112	)
Other Items – Net		90			(15	)
Income Tax Expense – Continuing Operations	$	4,073		$	8,562
Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%

Schedule of activity related to unrecognized tax benefits

(in thousands)	2015		2014
Balance on January 1	$	222	$	4,239
Increases Related to Tax Positions for Prior Years		--		137
Increases Related to Tax Positions for Current Year		44		--
Uncertain Positions Resolved During Year		--		--
Balance on March 31	$	266	$	4,376

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Rate and Regulatory Matters (Detail Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended	1 Months Ended
	Mar. 31, 2015	Dec. 31, 2011 mi Kv	Mar. 31, 2014 mi
Otter Tail Power Company
Regulatory Matters [Line Items]
Increase In reagent costs and emission allowances	$ 4.1
Reagent costs	3.6
Emission allowances	0.5
Otter Tail Power Company | Minnesota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	50.00%
Otter Tail Power Company | North Dakota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	40.00%
Otter Tail Power Company | South Dakota
Regulatory Matters [Line Items]
Percentage of reagent costs and emission allowances shared	10.00%
Otter Tail Power Company | Big Stone South - Brookings MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Expanded capacity of projects		345
Extended distance of transmission line		70
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission
Regulatory Matters [Line Items]
Expanded capacity of projects		345
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Minimum
Regulatory Matters [Line Items]
Extended distance of transmission line		160
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Maximum
Regulatory Matters [Line Items]
Extended distance of transmission line		170
Big Stone AQCS Project BART - compliant AQCS
Regulatory Matters [Line Items]
Current projected cost	384
Big Stone AQCS Project BART - compliant AQCS | Otter Tail Power Company
Regulatory Matters [Line Items]
Current projected cost	207
Percentage of projected cost	53.90%
Construction expenditures	$ 174.9
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project
Regulatory Matters [Line Items]
Extended distance of transmission line			250

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Discontinued Operations

3 Months Ended

Mar. 31, 2015

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

16. Discontinued Operations

In 2014 the Company entered into signed letters of intent to sell its two construction companies that made up its Construction segment. On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor headquartered in Kansas City, Missouri, for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) in exchange for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets to be determined within 90 days of closing. The Company recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. The assets, liabilities, operating results and cash flows of Foley and AEV, Inc. are being reported as discontinued operations as of, and for the periods preceding, March 31, 2015. On February 8, 2013 the Company completed the sale of substantially all the assets of its former waterfront equipment manufacturing company previously included in the Company’s Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing company. The following summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2015 and 2014, include the operating results of Foley, AEV, Inc. and residual expenses from the Company’s former wind tower and waterfront equipment manufacturers:

	For the Three Months Ended  March 31,
(in thousands)	2015			2014
Operating Revenues	$	18,724		$	25,506
Operating Expenses		22,141			26,368
Goodwill Impairment Charge		1,000			--
Operating Loss		(4,417	)		(862	)
Other (Deductions) Income		(31	)		288
Income Tax Benefit		(1,376	)		(225	)
Net Loss from Operations		(3,072	)		(349	)
Gain on Disposition Before Taxes		12,042			--
Income Tax Expense on Disposition		4,816			--
Net Gain on Disposition		7,226			--
Net Income (Loss)	$	4,154		$	(349	)

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2015 and December 31, 2014:

(in thousands)	March 31, 2015		December 31,  2014
Current Assets	$	26,928	$	35,174
Goodwill and Intangibles		1,814		2,814
Net Plant		4,429		10,669
Assets of Discontinued Operations	$	33,171	$	48,657
Current Liabilities	$	15,616	$	22,864
Deferred Income Taxes		5,116		4,695
Liabilities of Discontinued Operations	$	20,732	$	27,559

Foley and AEV, Inc.entered into fixed-price construction contracts. Revenues under these contracts have been 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.

The following tables summarize costs incurred and billings and estimated earnings recognized on uncompleted contracts included in current assets and current liabilities of discontinued operations:

	March 31,			December 31,
(in thousands)	2015			2014
Costs Incurred on Uncompleted Contracts	$	339,594		$	402,332
Less Billings to Date		(354,256	)		(411,909	)
Plus Estimated Earnings Recognized		14,458			15,154
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

	March 31,			December 31,
(in thousands)	2015			2014
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts	$	3,216		$	8,133
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts		(3,420	)		(2,556	)
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$	(204	)	$	5,577

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. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in $2.3 million in pretax charges in the first quarter of 2015.

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge as a result of a revision in the estimated valuation of Foley due to first quarter financial results. The first quarter 2015 goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations.

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

(in thousands)	2015			2014
Warranty Reserve Balance, January 1	$	2,527		$	3,087
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(6	)		--
Decrease in Warranty Estimates for Prior Years		--			(100	)
Warranty Reserve Balance, March 31	$	2,521		$	2,987

The warranty reserve balances as of March 31, 2015 relate entirely to warranties scheduled to expire over the next five years on products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products these companies produced prior to the companies being sold. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated results of operations and financial condition.

Retainage

Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction companies that have been retained by customers pending project completion:

	March 31,		December 31,
(in thousands)	2015		2014
Accounts Receivable Retained by Customers	$	4,018	$	6,759

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Rate and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2015

Rate and Regulatory Matters [Abstract]

Schedule of revenues recorded under rate riders

	Three Months Ended March 31,
Rate Rider (in thousands)	2015		2014
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,928	$	1,521
Transmission Cost Recovery		1,615		2,304
Environmental Cost Recovery		2,557		1,763
North Dakota
Renewable Resource Adjustment		1,883		1,435
Transmission Cost Recovery		1,936		1,514
Environmental Cost Recovery		2,156		1,522
Big Stone II Project Costs		--		361
South Dakota
Transmission Cost Recovery		363		346
Environmental Cost Recovery		504		--
1Includes MNCIP costs recovered in base rates.

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Segment Information (Detail Textuals)	3 Months Ended
	Mar. 31, 2015 Segment
Segment Reporting [Abstract]
Number of reportable segments	3

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Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 5) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 244	$ 244

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Consolidated Statements of Income (not audited) (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Income tax expense (benefit) on income (loss) from discontinued operation	$ (1,376)	$ (225)
Income tax (benefit) expense on impairment	0
Income tax (benefit) expense on gain from disposition	$ 4,816

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Discontinued Operations - Summary of costs incurred and billings and estimated earnings recognized on uncompleted contracts (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Costs Incurred on Uncompleted Contracts	$ 339,594	$ 402,332
Less Billings to Date	(354,256)	(411,909)
Plus Estimated Earnings Recognized	14,458	15,154
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts	$ (204)	$ 5,577

XML

Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2015

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2015 and 2014.

Major Capital Expenditure Projects

Big Stone Plant Air Quality Control System (AQCS)—The South Dakota Department of Environmental and Natural Resources determined that the Big Stone Plant is subject to Best-Available Retrofit Technology (BART) requirements of the Clean Air Act, based on air dispersion modeling indicating that Big Stone Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan.

OTP is currently in the final stages of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through March 31, 2015 is $174.9 million, excluding Allowance for Funds Used During Construction (AFUDC).

Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. The St. Cloud to Alexandria portion of the Fargo Project was placed into service on April 23, 2014. The third and final phase of the Fargo Project, from Alexandria to Fargo, was energized on April 2, 2015.

Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—The MISO granted unconditional approval of the Brookings Project as a Multi-Value Project (MVP) under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011.The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized in April 2014. This line was placed into service on March 26, 2015.

The Big Stone South – Brookings MVP and CapX2020 Project—This is a planned 345 kV transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013 and granted approval of a route permit for the southern portion of the line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017.

The Big Stone South – Ellendale MVP—This is a proposed 345 kV transmission line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU).  MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019.

Recovery of OTP’s transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

Reagent Costs and Emission Allowances

OTP’s system wide costs for reagents and Cross-State Air Pollution Rule (CSAPR) emissions allowances are expected to increase to approximately $4.1 million annually, $3.6 million for reagents and $0.5 million for emission allowances. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs will be phased in during 2015 and 2016 when the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects are completed and in service. Emissions allowance costs are being incurred during 2015 to maintain compliance with CSAPR rules, which became effective January 1, 2015.

Minnesota

2010 General Rate Case—OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. 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%.

Minnesota Conservation Improvement Programs (MNCIP)—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 September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. Based on results from the 2014 MNCIP program year, OTP now estimates a financial incentive for 2014 of $3.0 million. OTP is estimating a lower incentive for 2014 in response to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016.  Additionally, OTP estimated it saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. OTP requested approval for recovery of its 2014 MNCIP financial incentive and 2014 program costs not included in base rates from the MPUC in an April 1, 2015 filing.

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. OTP filed its annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of Certificate of Need estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015.
 

Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. OTP filed its 2014 annual update on July 31, 2014, requesting a $4.1 million annual increase in the rider from $6.1 million to $10.2 million. The MPUC approved OTP’s ECR rider annual update request on November 24, 2014, effective December 1, 2014. Because the effective date was two months behind the anticipated implementation date for the updated rate and a portion of the requested increase had been collected under the initial rate, the approved updated rate is based on a revenue requirement of $9.8 million. The rate will continue to be updated in annual filings with the MPUC until the costs are rolled into base rates at an undetermined future date.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs will be reviewed in OTP’s next general rate case in Minnesota and considered for recovery either through the FCA rider or general rates.

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.Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

Renewable Resource Adjustment—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 with a return on investment at the level approved in OTP’s most recent general rate case. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the updated rates implemented on April 1, 2013. The NDPSC approved OTP’s 2013 annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. OTP submitted its 2014 annual update to the NDRRA on December 31, 2014, which was approved by the NDPSC on March 25, 2015 with an effective date of April 1, 2015. In each instance the NDRRA rates have been based upon a return on investment at the rate of return approved in the OTP’s last general rate case. Approved in the 2014 annual update was a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill.

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. For qualifying projects, the law authorizes a current return on construction work in progress and a return on investment at the level approved in the utility’s most recent general rate case. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million. The NDPSC approved the annual update on December 17, 2014 with an effective date of January 1, 2015.

Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. The ECR provides for a current return on construction work in progress and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR with a proposed implementation date of July 1, 2015.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through the modification of the ECR rider to add a new variable monthly reagent and emissions allowance charge effective May 1, 2015.

South Dakota

2010 General Rate Case—On April 21, 2011, the SDPUC issued a written order approving an overall revenue increase for OTP of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50%. Final rates were effective with bills rendered on and after June 1, 2011.

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s following annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s most recent annual update on February 13, 2015 with an effective date of March 1, 2015.

Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s jurisdictional share of costs and provide a return on investment for the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014.

Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended March 31,
Rate Rider (in thousands)	2015		2014
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,928	$	1,521
Transmission Cost Recovery		1,615		2,304
Environmental Cost Recovery		2,557		1,763
North Dakota
Renewable Resource Adjustment		1,883		1,435
Transmission Cost Recovery		1,936		1,514
Environmental Cost Recovery		2,156		1,522
Big Stone II Project Costs		--		361
South Dakota
Transmission Cost Recovery		363		346
Environmental Cost Recovery		504		--
1Includes MNCIP costs recovered in base rates.

FERC

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the return on equity (ROE) component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. Settlement discussions did not resolve the dispute and the FERC set the proceeding to a Track II Hearing for complex cases that can take several months to decide with a FERC decision anticipated in fall 2016 at the earliest. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the resolution of the return on equity complaint proceeding.

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from the current 12.38% to a proposed 8.67%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. As of April 30, 2015, the FERC had not responded to the complaint.

In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff.

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Forward Contracts Classified as Derivatives - Change in consolidated balance sheet location and fair values of forward contracts for purchase and sale of electricity (Details 1) (Forward Electricity Contracts, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Forward Electricity Contracts
Derivatives Fair Value [Roll Forward]
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year		$ 115
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods		(72)
Changes in Fair Value of Contracts Entered into in Prior Periods		(43)
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period
Changes in Fair Value of Contracts Entered into in Current Period		39
Cumulative Fair Value Adjustments Included in Earnings - End of Period		$ 39

XML

Fair Value of Financial Instruments (Detail Textuals)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Otter Tail Corporation Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis	LIBOR
Basis spread on variable rate	1.75%
OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Description of variable rate basis		LIBOR
Basis spread on variable rate		1.25%

XML

Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 1,643	$ 884
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	49	42
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	98	123
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	157	135
Restricted Stock Units (RSUs) | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	66	58
Restricted Stock Units (RSUs) | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	253
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 1,020	$ 526

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2015

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of amount of regulatory assets and liabilities

	March 31, 2015						Remaining  Recovery/  Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,465	$	99,659	$	107,124	see below
Deferred Marked-to-Market Losses1		2,059		9,226		11,285	69 months
Conservation Improvement Program Costs and Incentives2		3,815		3,511		7,326	27 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,305		5,305	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		2,152		1,835		3,987	12 months
Big Stone II Unrecovered Project Costs – Minnesota1		601		3,086		3,687	93 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,140		636		2,776	24 months
Debt Reacquisition Premiums1		351		1,802		2,153	210 months
Deferred Income Taxes1		--		1,461		1,461	asset lives
Recoverable Fuel and Purchased Power Costs1		1,249		--		1,249	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		718		818	98 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		420		--		420	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
North Dakota Renewable Resource Rider Accrued Revenues2		--		61		61	12 months
Total Regulatory Assets	$	20,352	$	127,368	$	147,720
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,220	$	75,220	asset lives
North Dakota Renewable Resource Rider Accrued Refund		1,803		--		1,803	12 months
Deferred Income Taxes		--		1,447		1,447	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		908		908	see below
Minnesota Environmental Cost Recovery Rider Accrued Refund		451		--		451	12 months
Deferred Marked-to-Market Gains		204		177		381	58 months
Big Stone II Over Recovered Project Costs – North Dakota		111		--		111	9 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		99		105	225 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		86		--		86	12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		35		--		35	12 months
Total Regulatory Liabilities	$	2,744	$	77,851	$	80,595
Net Regulatory Asset Position	$	17,608	$	49,517	$	67,125
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.

	December 31, 2014						Remaining  Recovery/  Refund Period
(in thousands)	Current		Long-Term		Total
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	7,464	$	101,526	$	108,990	see below
Deferred Marked-to-Market Losses1		4,492		9,396		13,888	72 months
Conservation Improvement Program Costs and Incentives2		5,843		2,500		8,343	18 months
Accumulated ARO Accretion/Depreciation Adjustment1		--		5,190		5,190	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		592		3,207		3,799	96 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		943		2,455		3,398	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		2,585		807		3,392	24 months
Debt Reacquisition Premiums1		351		1,890		2,241	213 months
Deferred Income Taxes1		--		2,086		2,086	asset lives
Recoverable Fuel and Purchased Power Costs1		1,114		--		1,114	12 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		859		--		859	12 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		743		843	101 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		706		--		706	12 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues2		186		--		186	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		--		68		68	see below
South Dakota Environmental Cost Recovery Rider Accrued Revenues2		38		--		38	12 months
Total Regulatory Assets	$	25,273	$	129,868	$	155,141
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	74,237	$	74,237	asset lives
Deferred Income Taxes		--		1,550		1,550	asset lives
North Dakota Renewable Resource Rider Accrued Refund		933		85		1,018	15 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		784		784	see below
Deferred Marked-to-Market Gains		--		257		257	67 months
Big Stone II Over Recovered Project Costs – North Dakota		147		--		147	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		100		106	228 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		48		--		48	12 months
South Dakota – Nonasset-Based Margin Sharing Excess		24		--		24	12 months
Total Regulatory Liabilities	$	1,158	$	77,013	$	78,171
Net Regulatory Asset Position	$	24,115	$	52,855	$	76,970
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.

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Commitments and Contingencies (Detail Textuals) (Otter Tail Power Company, USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended	1 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Apr. 30, 2015
Commitments and Contingencies Disclosure [Line Items]
Amount of reduction in revenue and liability	$ 0.6
Capacity and Energy Requirements
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	2.9
Contracts expiration year	2039
Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	10.0
Contracts expiration year	2015, 2016, 2017 and 2040
Loss contingency, range of possible loss, maximum	5.0
Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	106.1	106.6
Subsequent event
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount			$ 2.8

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Summary of Significant Accounting Policies - Inventories (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Finished Goods	$ 27,607	$ 27,998
Work in Process	9,894	10,628
Raw Material, Fuel and Supplies	47,014	46,577
Total Inventories	$ 84,515	$ 85,203

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Income Tax Expense Continuing Operations

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Income Tax Expense - Continuing Operations

14. Income Tax Expense – Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three month periods ended March 31, 2015 and 2014:

	Three Months Ended March 31,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	17,854		$	30,341
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		6,963			11,833
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,054	)		(2,252	)
Section 199 Domestic Production Activities Deduction		(362	)		(358	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(189	)
AFUDC Equity		(100	)		(133	)
Corporate Owned Life Insurance		(80	)		(112	)
Other Items – Net		90			(15	)
Income Tax Expense – Continuing Operations	$	4,073		$	8,562
Effective Income Tax Rate – Continuing Operations		22.8	%		28.2	%

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2015		2014
Balance on January 1	$	222	$	4,239
Increases Related to Tax Positions for Prior Years		--		137
Increases Related to Tax Positions for Current Year		44		--
Uncertain Positions Resolved During Year		--		--
Balance on March 31	$	266	$	4,376

The balance of unrecognized tax benefits as of March 31, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2015 is not expected to change significantly within the next twelve months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. No interest is accrued on tax uncertainties as of March 31, 2015.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of March 31, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2011. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at March 31, 2015 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014.