Edgar Filing: Otter Tail Corp

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

September 30, 2015

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

For the transition period from

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 ¨

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 ¨

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 ¨

Non-accelerated filer ¨	Smaller reporting company ¨

(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 ¨ No x

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

October 31, 2015 – 37,743,953 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.

Item 1.	Financial Statements

	Consolidated Balance Sheets – September 30, 2015 and December 31, 2014 (not audited)	2 & 3

	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2015 and 2014 (not audited)	4

	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2015 and 2014 (not audited)	5

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2015 and 2014 (not audited)	6

	Condensed Notes to Consolidated Financial Statements (not audited)	7-33

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34-50

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51

Item 4.	Controls and Procedures	51

Part II. Other Information

Item 1.	Legal Proceedings	52

Item 1A.	Risk Factors	52

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 6.	Exhibits	52

Signatures		53

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	September 30, 2015		December 31, 2014

Assets

Current Assets
Cash and Cash Equivalents	$	548	$	--
Accounts Receivable:
Trade—Net		76,502		60,172
Other		17,614		13,179
Inventories		83,167		85,203
Deferred Income Taxes		53,515		49,482
Unbilled Revenues		14,973		17,996
Regulatory Assets		18,250		25,273
Other		9,311		7,187
Assets of Discontinued Operations		110		48,657
Total Current Assets		273,990		307,149

Investments		7,875		8,582
Other Assets		31,009		30,111
Goodwill		38,419		31,488
Other Intangibles—Net		16,047		11,251

Deferred Debits
Unamortized Debt Expense		3,772		4,300
Regulatory Assets		123,903		129,868
Total Deferred Debits		127,675		134,168

Plant
Electric Plant in Service		1,590,287		1,545,112
Nonelectric Operations		195,127		175,159
Construction Work in Progress		284,700		248,677
Total Gross Plant		2,070,114		1,968,948
Less Accumulated Depreciation and Amortization		708,627		700,418
Net Plant		1,361,487		1,268,530
Total Assets	$	1,856,502	$	1,791,279

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	September 30, 2015			December 31, 2014

Liabilities and Equity

Current Liabilities
Short-Term Debt	$	86,952		$	10,854
Current Maturities of Long-Term Debt		221			201
Accounts Payable		96,434			107,013
Accrued Salaries and Wages		15,839			19,256
Accrued Taxes		11,987			13,793
Derivative Liabilities		15,922			14,230
Other Accrued Liabilities		7,466			8,793
Liabilities of Discontinued Operations		2,330			27,559
Total Current Liabilities		237,151			201,699

Pensions Benefit Liability		93,926			102,711
Other Postretirement Benefits Liability		54,503			53,638
Other Noncurrent Liabilities		24,043			26,794

Commitments and Contingencies (note 9)

Deferred Credits
Deferred Income Taxes		246,691			230,810
Deferred Tax Credits		24,976			26,384
Regulatory Liabilities		77,868			77,013
Other		1,099			975
Total Deferred Credits		350,634			335,182

Capitalization
Long-Term Debt, Net of Current Maturities		498,330			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—37,726,115 Shares; 2014—37,218,053 Shares		188,631			186,090
Premium on Common Shares		290,520			278,436
Retained Earnings		123,059			112,903
Accumulated Other Comprehensive Loss		(4,295	)		(4,663	)
Total Common Equity		597,915			572,766

Total Capitalization		1,096,245			1,071,255

Total Liabilities and Equity	$	1,856,502		$	1,791,279

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except share and per-share amounts)	2015			2014		2015			2014
Operating Revenues
Electric	$	100,538		$	89,376	$	304,998		$	301,328
Product Sales		99,485			107,149		286,019			304,527
Total Operating Revenues		200,023			196,525		591,017			605,855
Operating Expenses
Production Fuel - Electric		11,124			15,121		29,906			49,754
Purchased Power - Electric System Use		18,725			10,710		62,101			48,971
Electric Operation and Maintenance Expenses		32,648			33,346		107,929			107,742
Cost of Products Sold (depreciation included below)		78,428			85,384		224,912			239,501
Other Nonelectric Expenses		10,771			9,707		32,057			32,380
Depreciation and Amortization		15,141			14,557		44,337			43,296
Property Taxes - Electric		3,560			3,178		10,324			9,536
Total Operating Expenses		170,397			172,003		511,566			531,180
Operating Income		29,626			24,522		79,451			74,675
Interest Charges		7,730			7,688		23,175			21,909
Other Income		334			494		1,473			2,873
Income Before Income Taxes—Continuing Operations		22,230			17,328		57,749			55,639
Income Tax Expense—Continuing Operations		6,521			4,156		14,602			12,802
Net Income from Continuing Operations		15,709			13,172		43,147			42,837
Discontinued Operations
(Loss) Income - net of Income Tax (Benefit) Expense of ($168), $1,437, ($2,873) and $2,614 for the Respective Periods		(252	)		2,653		(4,316	)		4,411
Impairment Loss - net of Income Tax Benefit of $0 for the Nine Months ended September 30, 2015		--			--		(1,000	)		--
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of ($43) and $4,493 for the three and nine months ended September 30, 2015		(65	)		--		6,932			--
Net (Loss) Income from Discontinued Operations		(317	)		2,653		1,616			4,411
Net Income		15,392			15,825		44,763			47,248

Average Number of Common Shares Outstanding—Basic		37,575,413			36,596,396		37,417,283			36,415,500
Average Number of Common Shares Outstanding—Diluted		37,794,543			36,838,990		37,636,413			36,658,257

Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	0.42		$	0.36	$	1.15		$	1.18
Discontinued Operations		(0.01	)		0.07		0.05			0.12
	$	0.41		$	0.43	$	1.20		$	1.30
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	0.42		$	0.36	$	1.15		$	1.17
Discontinued Operations		(0.01	)		0.07		0.04			0.12
	$	0.41		$	0.43	$	1.19		$	1.29

Dividends Declared Per Common Share	$	0.3075		$	0.3025	$	0.9225		$	0.9075

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2015			2014
Net Income	$	15,392		$	15,825		$	44,763		$	47,248
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		6			(37	)		1			(18	)
Income Tax (Expense) Benefit		(2	)		13			1			12
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		4			(24	)		(1	)		(23	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		205			50			616			151
Income Tax Expense		(82	)		(20	)		(247	)		(60	)
Pension and Postretirement Benefit Plans – net-of-tax		123			30			369			91
Total Other Comprehensive Income		127			6			368			68
Total Comprehensive Income	$	15,519		$	15,831		$	45,131		$	47,316

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Nine Months Ended September 30,
(in thousands)	2015			2014
Cash Flows from Operating Activities
Net Income	$	44,763		$	47,248
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		(6,932	)		--
Net Loss (Income) from Discontinued Operations		5,316			(4,411	)
Depreciation and Amortization		44,337			43,296
Deferred Tax Credits		(1,408	)		(1,361	)
Deferred Income Taxes		12,244			20,690
Change in Deferred Debits and Other Assets		13,839			4,299
Discretionary Contribution to Pension Plan		(10,000	)		(20,000	)
Change in Noncurrent Liabilities and Deferred Credits		4,345			(1,336	)
Allowance for Equity/Other Funds Used During Construction		(944	)		(1,180	)
Change in Derivatives Net of Regulatory Deferral		(28	)		214
Stock Compensation Expense—Equity Awards		1,428			1,126
Other—Net		(27	)		437
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(14,020	)		(16,023	)
Change in Inventories		5,721			(6,312	)
Change in Other Current Assets		2,163			3,231
Change in Payables and Other Current Liabilities		(17,490	)		(2,645	)
Change in Interest and Income Taxes Receivable/Payable		(1,499	)		1,028
Net Cash Provided by Continuing Operations		81,808			68,301
Net Cash Used in Discontinued Operations		(11,581	)		(21,273	)
Net Cash Provided by Operating Activities		70,227			47,028
Cash Flows from Investing Activities
Capital Expenditures		(115,321	)		(123,731	)
Net Proceeds from Disposal of Noncurrent Assets		2,956			1,419
Acquisition		(30,806	)		--
Cash used for Investments and Other Assets		(7,297	)		(2,148	)
Net Cash Used in Investing Activities - Continuing Operations		(150,468	)		(124,460	)
Net Proceeds from Sale of Discontinued Operations		32,765			--
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations		(1,769	)		694
Net Cash Used in Investing Activities		(119,472	)		(123,766	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(1,236	)		106
Net Short-Term Borrowings (Repayments)		76,098			(12,195	)
Proceeds from Issuance of Common Stock		11,340			13,331
Common Stock Issuance Expenses		(361	)		(412	)
Payments for Retirement of Capital Stock		(1,596	)		(459	)
Proceeds from Issuance of Long-Term Debt		--			150,000
Short-Term and Long-Term Debt Issuance Expenses		(7	)		(516	)
Payments for Retirement of Long-Term Debt		(149	)		(41,039	)
Common Dividends Paid		(34,607	)		(33,119	)
Net Cash Provided by Financing Activities – Continuing Operations		49,482			75,697
Net Cash Provided by (Used in) Financing Activities – Discontinued Operations		321			(106	)
Net Cash Provided by Financing Activities		49,803			75,591
Net Change in Cash and Cash Equivalents - Discontinued Operations		(10	)		(860	)
Net Change in Cash and Cash Equivalents		548			(2,007	)
Cash and Cash Equivalents at Beginning of Period		--			2,007
Cash and Cash Equivalents at End of Period	$	548		$	--

See accompanying condensed notes to consolidated financial statements.

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 and nine month periods ended September 30, 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. Provisions for sales returns are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as 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

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 September 30, 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 September 30, 2015 and December 31, 2014:

September 30, 2015 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Money Market Escrow Accounts – AEV, Inc. and Foley Company Sales	$	2,500
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	6,380
U.S. Government and U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,224
Other Assets:
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan		188
Total Assets	$	2,688	$	7,604
Liabilities:
Derivative Liabilities - Forward Gasoline Purchase Contracts			$	313
Derivative Liabilities - Forward Energy Contracts					$	15,609
Total Liabilities			$	313	$	15,609

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 September 30, 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 based on historical spreads. The September 30, 2015 Level 3 forward electric basis spreads ranged from $8.00 to $3.00 per megawatt-hour under the active trading hub price. The weighted average price was $31.16 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 September 30, 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, due to the effects of regulation, 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 or nine month periods ended September 30, 2015 and 2014.

The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the nine month periods ended September 30, 2015 and 2014:

	Nine Months Ended
	September 30,
(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		4,492			1,252
Net Changes in Fair Value of Contracts Entered into in Prior Periods		(6,470	)		5,622
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period		(15,609	)		(4,467	)
Net Loss Recognized as Regulatory Assets on Contracts Entered into in Period		--			--
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period	$	(15,609	)	$	(4,467	)

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2015		2014
Finished Goods	$	22,377	$	27,998
Work in Process		12,819		10,628
Raw Material, Fuel and Supplies		47,971		46,577
Total Inventories	$	83,167	$	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 in excess of their respective book values and not impaired. There were no changes to the carrying amounts of goodwill outstanding at December 31, 2014 in the first nine months of 2015. On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing Inc. (Impulse) of Dawsonville, Georgia. The newly acquired business will operate under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in acquired goodwill of $6,931,000.

The following table summarizes goodwill by business segment:

(in thousands)	Gross Balance December 31, 2014		Accumulated Impairments		Balance (net of impairments) December 31, 2014		Adjustments and Additions to Goodwill in 2015		Balance (net of impairments) September 30, 2015
Manufacturing	$	12,186	$	--	$	12,186	$	6,931	$	19,117
Plastics		19,302		--		19,302		--		19,302
Total	$	31,488	$	--	$	31,488	$	6,931	$	38,419

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 its Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s September 30, 2015 balance sheet. With the purchase of Impulse on September 1, 2015, the Company acquired customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete valued at $620,000 to be amortized over three years. The following table summarizes the components of the Company’s intangible assets at September 30, 2015 and December 31, 2014:

September 30, 2015 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	21,681	$	6,441	$	15,240	51-239 months
Covenant not to Compete		620		17		603	35 months
Other Intangible Assets Including Contracts		639		511		128	12 months
Emission Allowances		76		NA		76	Expensed as used
Total	$	23,016	$	6,969	$	16,047

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				Nine Months Ended
	September 30,				September 30,
(in thousands)	2015		2014		2015		2014
Amortization Expense – Intangible Assets	$	282	$	245	$	770	$	733

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		$	1,127			$	1,395			$	1,299			$	1,230			$	1,093

The following table presents a reconciliation of OTP’s emission allowances balance for the nine month period ended September 30, 2015:

	Nine Months Ended
(in thousands)	September 30, 2015
Emission Allowances Beginning Balance	$	--
Allowances Purchased		168
Allowances Used		(92	)
Emission Allowances Ending Balance	$	76

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2015		2014
Noncash Investing Activities:
Accounts Payable Outstanding Related to Capital Additions¹	$	23,886	$	21,512
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions²	$	2,126	$	5,058

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 lignite 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 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 initial delivery of coal to Coyote Station (anticipated in May 2016), by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide, among other things, that during any period between December 31, 2016 and any subsequent date on which CCMC makes initial delivery of coal, 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 the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through September 30, 2015 is $46.8 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 September 30, 2015 could be as high as $46.8 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.

Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

ASU 2015-03—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. As of September 30, 2015, the balance of the Company’s consolidated unamortized debt issuance costs related to its outstanding long-term debt was approximately $2.3 million.

ASU 2015-07—In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which eliminates the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company does not expect this new standard to have a material impact on its consolidated financial statements.

ASU 2015-11—In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update is effective prospectively for fiscal years and interim periods beginning after December 15, 2016, with early adoption permitted. The Company does not expect the adoption of the updated standard to have a material impact on its consolidated financial statements.

2. Acquisition and Segment Information

Acquisition

On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. Impulse, a full-service, high-tech metal fabricator located 30 miles north of Atlanta, Georgia, recorded revenues of $27 million in 2014. Impulse offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. The newly acquired business will operate under the name BTD-Georgia. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition will provide opportunities for growth in new and existing markets for BTD, and complementing production capabilities will expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company.

Below is condensed balance sheet information, at the date of the business combination, disclosing the preliminary allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia:

(in thousands)
Assets:
Current Assets	$	6,417
Goodwill		6,931
Other Intangible Assets		5,490
Fixed Assets		14,831
Total Assets	$	33,669
Liabilities:
Current Liabilities	$	2,852
Lease Obligation		11
Total Liabilities	$	2,863
Cash Paid	$	30,806

The final purchase price and assignment of asset values is subject to adjustment based on final agreement and settlement of the value of working capital transferred to BTD. In September 2015 BTD-Georgia recorded revenue of $2.0 million and a net loss of $0.3 million which included the amortization of $0.2 million in pre-tax costs of products sold related to the write up of finished goods inventory to fair market resale value on acquisition.

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, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

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

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

No single customer accounted for over 10% of the Company’s consolidated revenues in 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
United States of America		98.2%		95.0%		97.2%		95.9%
Mexico		0.2%		3.7%		1.5%		3.0%
Canada		1.4%		1.2%		1.1%		1.0%
All Other Countries (none greater than 0.06%)		0.2%		0.1%		0.2%		0.1%

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three and nine months ended September 30, 2015 and 2014 and total assets by business segment as of September 30, 2015 and December 31, 2014 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
Electric	$	100,567		$	89,410		$	305,078		$	301,409
Manufacturing		52,460			55,536			160,492			164,341
Plastics		47,025			51,613			125,531			140,186
Intersegment Eliminations		(29	)		(34	)		(84	)		(81	)
Total	$	200,023		$	196,525		$	591,017		$	605,855

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2015		2014		2015		2014
Electric	$	6,069	$	6,071	$	18,273	$	17,209
Manufacturing		900		812		2,578		2,433
Plastics		257		276		782		797
Corporate and Intersegment Eliminations		504		529		1,542		1,470
Total	$	7,730	$	7,688	$	23,175	$	21,909

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
Electric	$	4,761		$	1,714		$	9,995		$	6,472
Manufacturing		855			1,164			2,516			4,171
Plastics		2,206			1,888			6,159			6,135
Corporate		(1,301	)		(610	)		(4,068	)		(3,976	)
Total	$	6,521		$	4,156		$	14,602		$	12,802

Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
Electric	$	12,921		$	8,612		$	34,351		$	30,507
Manufacturing		1,714			2,899			4,810			8,095
Plastics		3,534			3,092			9,919			9,985
Corporate		(2,460	)		(1,431	)		(5,933	)		(5,750	)
Discontinued Operations		(317	)		2,653			1,616			4,411
Total	$	15,392		$	15,825		$	44,763		$	47,248

Identifiable Assets

	September 30,		December 31,
(in thousands)	2015		2014
Electric	$	1,510,141	$	1,472,647
Manufacturing		177,842		130,701
Plastics		89,392		87,356
Corporate		79,017		51,918
Assets of Discontinued Operations		110		48,657
Total	$	1,856,502	$	1,791,279

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 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 December 2015. OTP’s share of AQCS construction expenditures incurred through September 30, 2015 is $198.4 million.

Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—OTP has invested approximately $80.2 million and has a 13% ownership interest in this 240-mile transmission line. The final phase of this project was energized on April 2, 2015.

Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—OTP has invested approximately $25.4 million and has a 4.1% ownership interest in this 250-mile transmission line. 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. 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 the costs of transmission projects with regional benefits are properly assigned to those who benefit. The final segments of this line were energized 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 Northern States Power – MN (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. 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 NSP MN entered into agreements to construct the project. This line is expected to be in service in fall 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. The route permit remains under appeal. On June 12, 2015 OTP and MDU entered into agreements to construct the project. On September 29, 2015 an application for a request for an Amended Certificate of Corridor Compatibility and route permit was filed with the NDPSC for a slight route shift in North Dakota. This project is expected to be completed in 2019.

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

Reagent Costs and Emission Allowances

OTP’s systemwide costs for reagents and Cross-State Air Pollution Rule (CSAPR) emissions allowances are expected to increase to approximately $4.1 million annually through May 2021 when Hoot Lake Plant is expected to be retired, $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 recognized a financial incentive for 2014 of $3.0 million 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 saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015.

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 an annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of Certificate of Need estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of the capitalized internal costs and costs in excess of Certificate of Need estimates 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. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 seeking revenue recovery of approximately $7.8 million with a proposed effective date of April 1, 2016.

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 Construction Work in Progress (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. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the same rate in place.

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. These costs are currently being expensed as incurred.

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 an 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 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 CWIP 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 2014 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 2014 annual update on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to the North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015 with updated rates proposed to go into effect on January 1, 2016.

Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an Advance Determination of Prudence 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 CWIP and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed an 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. In this annual update, OTP updated the revenue requirements for the Big Stone Plant AQCS project and it proposed ECR recovery for the Hoot Lake Plant MATS project costs. The most recent update included a request to increase the ECR rider rate from 7.531% of base rates to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective 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 modification of the ECR rider, instead of recovery through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.

South Dakota

2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

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 OTP’s 2012 annual update to its South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s 2013 annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s 2014 annual update on February 13, 2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date of March 1, 2016.

Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million in annual revenue, with updated rates proposed to go into effect on November 1, 2015. The SDPUC approved the request in their order dated October 15, 2015.

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 and nine month periods ended September 30, 2015 and 2014:

	Three Months Ended September 30,				Nine Months Ended September 30,
Rate Rider (in thousands)	2015		2014		2015		2014
Minnesota
Conservation Improvement Program Costs and Incentives¹	$	1,970	$	1,262	$	5,508	$	4,254
Transmission Cost Recovery		1,141		1,114		3,968		5,194
Environmental Cost Recovery		2,565		1,722		7,722		5,188
North Dakota
Renewable Resource Adjustment		2,073		2,242		5,898		5,690
Transmission Cost Recovery		1,565		1,310		4,912		4,531
Environmental Cost Recovery		2,312		1,467		7,233		4,441
Big Stone II Project Costs		--		--		--		361
South Dakota
Transmission Cost Recovery		267		270		911		980
Environmental Cost Recovery		461		--		1,484		--
Conservation Improvement Program Costs and Incentives		234		148		464		329

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 which occurred in August 2015. A FERC decision is anticipated in fall 2016. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the 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. The FERC issued an order on June 18, 2015 setting the complaint for hearing to begin on February 16, 2016. A FERC decision is not expected until 2017.

OTP recorded reductions in revenue of $0.1 million for the three months ended September 30, 2015 and $0.9 million for the nine months ended September 30, 2015 and has a $0.9 million liability as of September 30, 2015 representing its 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.

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:

	September 30, 2015						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits¹	$	7,465	$	95,960		103,425	see below
Deferred Marked-to-Market Losses¹		1,693		13,916		15,609	63 months
Conservation Improvement Program Costs and Incentives²		4,275		1,892		6,167	21 months
Accumulated ARO Accretion/Depreciation Adjustment¹		--		5,546		5,546	asset lives
Big Stone II Unrecovered Project Costs – Minnesota¹		620		2,838		3,458	87 months
Debt Reacquisition Premiums¹		351		1,627		1,978	204 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues²		1,781		--		1,781	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up¹		1,170		429		1,599	24 months
Big Stone II Unrecovered Project Costs – South Dakota²		100		668		768	92 months
North Dakota Renewable Resource Rider Accrued Revenues²		--		750		750	18 months
Recoverable Fuel and Purchased Power Costs¹		687		--		687	12 months
Deferred Income Taxes¹		--		209		209	asset lives
North Dakota Environmental Cost Recovery Rider Accrued Revenues²		108		--		108	12 months
Minnesota Renewable Resource Rider Accrued Revenues²		--		68		68	see below
Total Regulatory Assets	$	18,250	$	123,903	$	142,153
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	75,373	$	75,373	asset lives
Deferred Income Taxes		--		1,244		1,244	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		1,155		1,155	see below
North Dakota Renewable Resource Rider Accrued Refund		868		--		868	12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		528		--		528	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		6		96		102	219 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		69		--		69	12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		57		--		57	12 months
Big Stone II Over Recovered Project Costs – North Dakota		37		--		37	3 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		17		--		17	12 months
Total Regulatory Liabilities	$	1,582	$	77,868	$	79,450
Net Regulatory Asset Position	$	16,668	$	46,035	$	62,703

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/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits¹	$	7,464	$	101,526	$	108,990	see 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 September 30, 2015 relate to forward purchases of energy scheduled for delivery through December 2020.

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

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

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

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 204 months.

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 September 30, 2015.

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.

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

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2015.

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.

North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to a return granted on the North Dakota share of amounts invested in the construction of the Big Stone Plant AQCS project and Hoot Lake Plant MATS project costs that have not been billed to North Dakota customers as of September 30, 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 rider 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.

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

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

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of September 30, 2015.

The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of September 30, 2015.

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 September 30, 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 September 30, 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.

North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of September 30, 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 expense or income item in the period in which the application of guidance under ASC 980 ceases.

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 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 September 30, 2015 and December 31, 2014 for the purchase of electricity were 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 are based on historical spreads. The fair value measurements of these forward energy contracts fell 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 September 30, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to September 30, 2015 and December 31, 2013 to September 30, 2014:

(in thousands)	September 30, 2015			December 31, 2014
Current Asset – Marked-to-Market Gain	$	--		$	257
Regulatory Asset – Current Deferred Marked-to-Market Loss		1,693			4,492
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss		13,916			9,396
Total Assets		15,609			14,145
Current Liability – Marked-to-Market Loss		(15,609	)		(13,888	)
Regulatory Liability – Current Deferred Marked-to-Market Gain		--			--
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain		--			(257	)
Total Liabilities		(15,609	)		(14,145	)
Net Fair Value of Marked-to-Market Energy Contracts	$	--		$	--

(in thousands)	Year-to-Date September 30, 2015		Year-to-Date September 30, 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		--		--
Cumulative Fair Value Adjustments Included in Earnings - End of Period	$	--	$	--

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2015		2014		2015		2014
Net Losses on Forward Electric Energy Contracts	$	--	$	--	$	--	$	(13	)

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 September 30, 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 September 30, 2015 and December 31, 2014 are indicated in the following table:

(in thousands)	September 30, 2015			December 31, 2014
Derivative assets subject to legally enforceable netting arrangements	$	--		$	257
Derivative liabilities subject to legally enforceable netting arrangements		(15,922	)		(14,230	)
Net balance subject to legally enforceable netting arrangements	$	(15,922	)	$	(13,973	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in loss positions as of September 30, 2015 and December 31, 2014:

Current Liability – Marked-to-Market Loss (in thousands)	September 30, 2015		December 31, 2014
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	313	$	45
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade¹		15,609		13,888
Loss Contracts with No Ratings Triggers or Deposit Requirements		--		297
Total Current Liability – Marked-to-Market Loss	$	15,922	$	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	$	15,609	$	13,888
Offsetting Gains with Counterparties under Master Netting Agreements		--		(257	)
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	15,609	$	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		2,798			12,050									14,848
Common Stock Retirements		(257	)		(1,339	)								(1,596	)
Net Income								44,763						44,763
Other Comprehensive Income											368			368
Tax Benefit – Stock Compensation					(55	)								(55	)
Employee Stock Incentive Plans Expense					1,428									1,428
Common Dividends ($0.9225 per share)								(34,607	)					(34,607	)
Balance, September 30, 2015	$	188,631		$	290,520		$	123,059		$	(4,295	)	$	597,915

Shelf Registration

On May 11, 2015, the Company filed a shelf registration statement with the U.S. Securities and Exchange Commission (SEC) under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company. On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million. In the third quarter of 2015 the Company received proceeds of $1,566,000 net of $20,000 paid to JPMS from the issuance of 57,769 shares under this program.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2014 through September 30, 2015:

Common Shares Outstanding, December 31, 2014	37,218,053
Issuances:
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	146,440
Cash Invested	70,424
Executive Stock Performance Awards (for 2012 grants)	89,991
At-the-Market Offering	95,929
Directors Deferred Compensation	36,828
Employee Stock Purchase Plan:
Cash Invested	42,253
Dividends Reinvested	20,562
Employee Stock Ownership Plan	21,137
Restricted Stock Issued to Directors	15,200
Stock Options Exercised	10,250
Vesting of Restricted Stock Units	10,400
Retirements:
Shares Withheld for Individual Income Tax Requirements	(51,352	)
Common Shares Outstanding, September 30, 2015	37,726,115

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three and nine month periods ended September 30, 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 following periods:

	Three Months ended September 30						Nine Months ended September 30
	2015			2014			2015			2014
Weighted Average Common Shares Outstanding – Basic		37,575,413			36,596,396			37,417,283			36,415,500
Plus:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers		235,900			225,800			235,900			225,800
Nonvested Restricted Shares		51,798			90,110			51,798			90,110
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		73,800			47,050			73,800			47,050
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,720			39,698			3,720			39,698
Potentially Dilutive Stock Options		--			13,900			--			13,900
Less:
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares		(146,088	)		(161,729	)		(146,088	)		(161,837	)
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options		--			(12,235	)		--			(11,964	)
Total Dilutive Shares		219,130			242,594			219,130			242,757
Weighted Average Common Shares Outstanding – Diluted		37,794,543			36,838,990			37,636,413			36,658,257

The effect of dilutive shares on earnings per share for the three and nine month periods ended September 30, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in any period.

7. Share-Based Payments

Stock Incentive Awards

On February 6, 2015 and April 13, 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		84,300	$	26.99	December 31, 2017
Restricted Stock Units Granted to Executive Officers:
Graded Vesting		22,700	$	31.68	25% per year through February 6, 2019
Cliff Vesting		6,400	$	31.675	100% on February 6, 2020

On April 13, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors and key employees under the 2014 Stock Incentive Plan:

Award	Shares/Units Granted		Grant-Date Fair Value per Award		Vesting
Restricted Stock Granted to Nonemployee Directors		15,200	$	31.775	25% per year through April 8, 2019
Restricted Stock Units Granted to Key Employees		11,900	$	27.05	100% on April 8, 2019

On September 30, 2015 the Company’s Board of Directors granted the following stock incentive awards to key employees of BTD-Georgia under the 2014 Stock Incentive Plan:

Award		Shares/Units Granted				Grant-Date Fair Value per Award				Vesting
Restricted Stock Units Granted to Key Employees			3,000			$	22.08			100% on September 1, 2019

Under the performance share award agreements the aggregate award for performance at target is 84,300 shares. For target performance the Company’s executive officers would earn an aggregate of 56,200 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 28,100 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 126,450 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 the target amount 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 restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted stock unit granted to executive officers and of each share of restricted stock granted to nonemployee directors was the average of the high and low market price per share on the dates of grant. The grant date fair value of each restricted stock unit granted to a key employee that is not an executive officer of the Company was based on the market value of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on the restricted stock unit over its vesting period. Under the terms of the restricted stock unit award agreements, all outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement.

As of September 30, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $3.3 million (before income taxes) which will be amortized over a weighted-average period of 2.6 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three and nine month periods ended September 30, 2015 and 2014 are presented in the table below:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2015		2014
Employee Stock Purchase Plan (15% discount)	$	44		$	43		$	138	$	130
Restricted Stock Granted to Directors		107			98			311		319
Restricted Stock Granted to Executive Officers		29			194			330		536
Restricted Stock Units Granted to Nonexecutive Employees		86			55			233		141
Restricted Stock Units Granted to Executive Officers		36			--			416		--
Stock Performance Awards Granted to Executive Officers		(142	)		(443	)		915		601
Totals	$	160		$	(53	)	$	2,343	$	1,727

8. Retained Earnings Restriction

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

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends on a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 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 46.9% and 57.3%. OTP’s equity to total capitalization ratio including short-term debt was 51.9% as of September 30, 2015. Total capitalization for OTP cannot currently exceed $1,056,300,000.

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 September 30, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $87.4 million.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2039.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2015, 2016, 2017 and 2040. 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 September 30, 2015 was 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. The remaining commitment under this contract as of September 30, 2015 was approximately $2.3 million. A five-year extension of an operating lease beginning in October 2015 increased operating lease commitments in the Plastics segment by $1.3 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 $2.4 million.

On December 19, 2014, the EPA’s rule regulating coal combustion residuals (CCR) went into effect. Many of the rule’s requirements are not effective until months, or in some cases years, after the rule’s effective date. The final rule regulates CCR as a non-hazardous solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA). Petitions for judicial review of the rule by industry and environmental groups are currently pending in the United States Court of Appeals for the District of Columbia Circuit. Briefing on the petitions is currently expected to extend until mid-2016 with a final decision sometime thereafter. The United States House of Representatives also passed a bill on July 22, 2015, to delay the effective date of certain portions of the CCR rule (the regulation of CCR under Subtitle D of RCRA). The bill would also eliminate some portions of the CCR rule, such as restrictions on how close existing CCR containment sites may be to the uppermost aquifer. The bill would also authorize states to enforce CCR standards, using the federal rule as minimum standards. Finally, the bill would prohibit the EPA from regulating CCR as a hazardous waste under Subtitle C of RCRA. The United States Senate is considering a similar bill. The Obama Administration has threatened to veto legislation designed to alter the CCR rule. The outcome of these judicial challenges and legislative actions cannot be predicted. Thus, uncertainty regarding the status of the CCR rule is likely to continue for a period of time.

The CCR 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. Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems.

In the second quarter of 2015, subsequent to publication of the CCR rule, OTP completed an assessment of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it has no immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but has discontinued the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally, OTP has identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the costs to reclaim the area have always been included in Big Stone Plant’s estimated removal costs currently being recovered as a component of depreciation expense. Therefore, the establishment of the ARO will have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when incurred, will be charged against, and reduce, the accumulated ARO liability.

In 2014, the EPA published proposed standards of performance for CO₂ emissions from new fossil fuel-fired power plants, proposed CO₂ emission guidelines for existing fossil fuel-fired power plants and proposed CO₂ standards of performance for CO₂ emissions from reconstructed and modified fossil fuel-fired power plants, essentially requiring that such plants install modern technology when modifying or reconstructing to reduce their emissions. The EPA announced final rules for each of these proposals on August 3, 2015. For existing sources, states are required to develop and submit plans, either individually or with other states, setting forth how they will achieve the individualized, reduced CO₂ emission rates that the EPA has identified. Those state plans are due by September 6, 2016, or at a minimum states must make an initial submittal by that date in order to receive a two-year extension, such that final state plans are due by September 6, 2018. The EPA published the final rules on October 23, 2015, which triggered a 60-day period within which petitions for judicial review may be filed. Many groups and states are expected to challenge the rules. The outcome of these judicial challenges cannot be predicted. Consequently, uncertainty regarding the status of the rules will likely continue for some time. OTP is currently assessing the potential impact of the final rules on existing affected sources of CO₂ emissions at OTP.

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 September 30, 2015 will not be material.

10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on September 30, 2015		Restricted due to Outstanding Letters of Credit		Available on September 30, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	75,881	$	--	$	74,119	$	138,872
OTP Credit Agreement		170,000		11,071		310		158,619		169,440
Total	$	320,000	$	86,952	$	310	$	232,738	$	308,312

On October 29, 2015 both the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were amended to extend the expiration dates by one year from October 29, 2019 to October 29, 2020.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2015 and December 31, 2014:

September 30, 2015 (in thousands)	OTP		Varistar		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	11,071	$	--	$	75,881	$	86,952
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						201		201
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021						1,010		1,010
BTD-Georgia Capital Lease, 7.00%, Retired October 19, 2015			$	11				11
Total	$	445,000	$	11	$	53,541	$	498,552
Less: Current Maturities				11		210		221
Unamortized Debt Discount						1		1
Total Long-Term Debt	$	445,000	$	--	$	53,330	$	498,330
Total Short-Term and Long-Term Debt (with current maturities)	$	456,071	$	11	$	129,421	$	585,503

December 31, 2014 (in thousands)	OTP		Varistar		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
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

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 September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2015			2014
Service Cost—Benefit Earned During the Period	$	1,514		$	1,150		$	4,544		$	3,499
Interest Cost on Projected Benefit Obligation		3,336			3,263			10,008			9,833
Expected Return on Assets		(4,595	)		(4,184	)		(13,787	)		(12,557	)
Amortization of Prior-Service Cost:
From Regulatory Asset		47			64			141			193
From Other Comprehensive Income¹		2			2			4			5
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,669			809			5,007			2,545
From Other Comprehensive Income¹		42			22			128			68
Net Periodic Pension Cost	$	2,015		$	1,126		$	6,045		$	3,586
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 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 September 30,					Nine Months Ended September 30,
(in thousands)	2015		2014			2015		2014
Service Cost—Benefit Earned During the Period	$	48	$	13		$	142	$	38
Interest Cost on Projected Benefit Obligation		380		380			1,142		1,140
Amortization of Prior-Service Cost:
From Regulatory Asset		5		5			13		16
From Other Comprehensive Income¹		9		13			28		39
Amortization of Net Actuarial Loss:
From Regulatory Asset		83		35			250		106
From Other Comprehensive Income²		151		12			452		35
Net Periodic Pension Cost	$	676	$	458		$	2,027	$	1,374
¹Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	3	$	6		$	11	$	16
Other Nonelectric Expenses		6		7			17		23
²Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	78	$	33		$	233	$	99
Other Nonelectric Expenses		73		(21	)		219		(64	)

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 September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2015			2014
Service Cost—Benefit Earned During the Period	$	324		$	263		$	972		$	791
Interest Cost on Projected Benefit Obligation		524			550			1,573			1,650
Amortization of Prior-Service Cost:
From Regulatory Asset		52			52			154			154
From Other Comprehensive Income¹		1			1			4			4
Net Periodic Postretirement Benefit Cost	$	901		$	866		$	2,703		$	2,599
Effect of Medicare Part D Subsidy	$	(372	)	$	(237	)	$	(1,115	)	$	(711	)
¹Corporate cost included in Other Nonelectric Expenses.

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 September 30, 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.

	September 30, 2015						December 31, 2014
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	548		$	548		$	--		$	--
Short-Term Debt		(86,952	)		(86,952	)		(10,854	)		(10,854	)
Long-Term Debt including Current Maturities		(498,551	)		(568,307	)		(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 and nine month periods ended September 30, 2015 and 2014:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2015			2014			2015			2014
Income Before Income Taxes – Continuing Operations	$	22,230		$	17,328		$	57,749		$	55,639
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		8,670			6,758			22,522			21,699
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,437	)		(1,362	)		(5,147	)		(5,478	)
Section 199 Domestic Production Activities Deduction		(362	)		(416	)		(1,087	)		(1,123	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)		(637	)		(637	)
Employee Stock Ownership Plan Dividend Deduction		(171	)		(186	)		(514	)		(568	)
Investment Tax Credits		(143	)		(127	)		(428	)		(380	)
Allowance for Funds Used During Construction – Equity		(144	)		(164	)		(369	)		(461	)
Corporate Owned Life Insurance		185			(17	)		(39	)		(328	)
Research and Development Tax Credits		--			(219	)		--			(219	)
Adjustment for Uncertain Tax Positions		281			119			367			119
Other Items – Net		(146	)		(18	)		(66	)		178
Income Tax Expense – Continuing Operations	$	6,521		$	4,156		$	14,602		$	12,802
Effective Income Tax Rate – Continuing Operations		29.3	%		24.0	%		25.3	%		23.0	%

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		236		256
Increases Related to Tax Positions for Current Year		131		--
Uncertain Positions Resolved During Year		--		--
Balance on September 30	$	589	$	4,495

The balance of unrecognized tax benefits as of September 30, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 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 September 30, 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 September 30, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2012 for federal and North Dakota state income taxes and for tax years prior to 2013 for Minnesota state income taxes.

16. Discontinued Operations

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 $6.3 million in adjustments for working capital and other related items expected to be received in fourth quarter 2015. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015. The Company has recorded a $7.1 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, September 30, 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 and nine month periods ended September 30, 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 September 30,						For the Nine Months Ended September 30,
(in thousands)	2015			2014			2015			2014
Operating Revenues	$	--		$	45,846		$	24,623		$	111,599
Operating Expenses		420			42,034			31,770			105,153
Goodwill Impairment Charge		--			--			1,000			--
Operating (Loss) Income		(420	)		3,812			(8,147	)		6,446
Interest Charges		--			(1	)		--			--
Other Income (Deductions)		--			277			(42	)		579
Income Tax (Benefit) Expense		(168	)		1,437			(2,873	)		2,614
Net (Loss) Income from Operations		(252	)		2,653			(5,316	)		4,411
(Loss) Gain on Disposition Before Taxes		(108	)		--			11,425			--
Income Tax (Benefit) Expense on Disposition		(43	)		--			4,493			--
Net (Loss) Gain on Disposition		(65	)		--			6,932			--
Net (Loss) Income	$	(317	)	$	2,653		$	1,616		$	4,411

The above results for the three months ended September 30, 2015 include a net loss from operations of $0.2 million from Foley. Included in net income from operations for the three months ended September 30, 2014 are $1.3 million from AEV, Inc., $1.1 million from Foley and $0.2 million from the Company’s former waterfront equipment manufacturer related to a gain on the sale of residual assets.

The above results for the nine months ended September 30, 2015 include net losses from operations of $4.1 million from Foley, $0.8 million from AEV, Inc. and $0.6 million from the Company’s former waterfront equipment manufacturer mainly related to the settlement of a warranty claim in the second quarter of 2015 and net income of $0.2 million from the Company’s former wind tower manufacturer related to a reduction in warranty reserves for expired warranties. The above results for the nine months ended September 30, 2014 include net income from operations of $2.4 million from Foley, $1.8 million from AEV, Inc. and $0.2 million from the Company’s former waterfront equipment manufacturer related to a gain on the sale of residual assets.

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $4.4 million in 2015.

In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge 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.

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2015 and December 31, 2014:

(in thousands)	September 30, 2015		December 31, 2014
Current Assets	$	110	$	35,174
Goodwill and Intangibles		--		2,814
Net Plant		--		10,669
Assets of Discontinued Operations	$	110	$	48,657
Current Liabilities	$	2,330	$	22,864
Deferred Income Taxes		--		4,695
Liabilities of Discontinued Operations	$	2,330	$	27,559

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		(115	)		(13	)
Decrease in Warranty Estimates for Prior Years		(100	)		(175	)
Warranty Reserve Balance, September 30	$	2,312		$	2,899

The warranty reserve balances as of September 30, 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.

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 and nine month periods ended September 30, 2015 and 2014, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2015 and our business outlook for the remainder of 2015.

Comparison of the Three Months Ended September 30, 2015 and 2014

Consolidated operating revenues were $200.0 million for the three months ended September 30, 2015 compared with
$196.5 million for the three months ended September 30, 2014. Operating income was $29.6 million for the three months ended September 30, 2015 compared with $24.5 million for the three months ended September 30, 2014. The Company recorded diluted earnings per share from continuing operations of $0.42 for the three months ended September 30, 2015 compared with $0.36 for the three months ended September 30, 2014, and total diluted earnings per share of $0.41 for the three months ended September 30, 2015 compared with $0.43 for the three months ended September 30, 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 September 30, 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)	September 30, 2015		September 30, 2014
Operating Revenues:
Electric	$	29	$	34
Nonelectric		--		--
Cost of Products Sold		1		28
Other Nonelectric Expenses		28		6

Electric

	Three Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Retail Sales Revenues	$	89,140	$	78,944	$	10,196			12.9
Wholesale Revenues – Company Generation		377		1,770		(1,393	)		(78.7	)
Net Revenue – Energy Trading Activity		2		129		(127	)		(98.4	)
Other Revenues		11,048		8,567		2,481			29.0
Total Operating Revenues	$	100,567	$	89,410	$	11,157			12.5
Production Fuel		11,124		15,121		(3,997	)		(26.4	)
Purchased Power – System Use		18,725		10,710		8,015			74.8
Other Operation and Maintenance Expenses		32,648		33,346		(698	)		(2.1	)
Depreciation and Amortization		11,190		11,033		157			1.4
Property Taxes		3,560		3,178		382			12.0
Operating Income	$	23,320	$	16,022	$	7,298			45.5
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,082,062		1,003,365		78,697			7.8
Wholesale kwh Sales – Company Generation		22,116		58,992		(36,876	)		(62.5	)
Wholesale kwh Sales – Purchased Power Resold		10		43		(33	)		(76.7	)
Heating Degree Days		20		58		(38	)		(65.5	)
Cooling Degree Days		396		262		134			51.1

The $10.2 million increase in retail revenue includes:

A $5.1 million increase in fuel and purchased power costs being recovered in revenue related to an 11.4% increase in the combined cost of fuel and purchased power per kwh generated and purchased for system use and a 7.8% increase in retail kwh sales. The increase in the combined cost of fuel and purchased power per kwh is a function of a reduction in the availability of Otter Tail Power Company’s (OTP) generation resources.

A $2.1 million increase in Environmental Cost Recovery (ECR) rider revenues related to: (1) earning a return in North Dakota and Minnesota on increasing amounts invested in the new air quality control system (AQCS) at Big Stone Plant, (2) earning a return on the Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project in North Dakota beginning in 2015, and (3) the initiation of an ECR rider in South Dakota in December 2014 to recover costs and earn returns on amounts invested in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

A $1.4 million increase in revenues related to increased retail kwh sales to residential and commercial customers driven by warmer weather in the third quarter of 2015 compared with the third quarter of 2014, evidenced by a 51.1% increase in cooling degree days between the quarters.

A $0.8 million increase in revenues recoverable under Conservation Improvement Program (CIP) riders related to increases in CIP accrued incentives and recoverable expenditures.

A $0.7 million increase in revenues mainly related to increased sales to pipeline customers.

Wholesale electric revenues from company-owned generation decreased $1.4 million as a result of a 62.5% reduction in wholesale kwh sales combined with a 43.2% decrease in revenue per wholesale kwh sold. The decrease in wholesale kwh sales was mainly due to OTP having fewer resources available for selling into the wholesale market in the third quarter of 2015 as Big Stone Plant was off line for the entire month of July for an extended maintenance outage that required off-site turbine blade replacements and repairs and Coyote Station was operating at reduced load due to ongoing repairs related to a December 2014 boiler feed pump failure and ensuing fire. Hoot Lake Plant was curtailed due to low wholesale market prices for electricity, which was a factor contributing to a strategic decision to shut down Hoot Lake Plant’s Unit 3 for preventative maintenance in September 2015. The decrease in wholesale prices for electricity is mainly due to lower prices for natural gas used in the generation of electricity in the third quarter of 2015 compared with the third quarter of 2014.

The $2.5 million increase in other electric revenues includes:

A $2.0 million increase in Midcontinent Independent System Operator, Inc. (MISO) transmission tariff revenues related to increased investment in regional transmission lines including returns on and recovery of Capacity Expansion 2020 (CapX2020) and MISO designated Multi-Value Project (MVP) investment costs and operating expenses.

A $0.5 million increase in revenue related to work performed for other regional transmission owners between the periods.

Production fuel costs to serve retail customers decreased $3.2 million and $0.8 million for wholesale sales as a result of a 34.5% 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 $8.0 million, reflecting an $8.9 million volume variance due to a 90.0% increase in kwhs purchased, partially offset by a $0.9 million price variance due to an 8.0% decrease in the cost per kwh purchased. The increase in power purchases for retail sales was necessitated by the reduced availability of OTP generating capacity discussed above. The decreased cost per kwh purchased was driven by lower prices for natural gas used in the generation of electricity.

Electric operating and maintenance expenses decreased $0.7 million mainly as a result of:

A $1.7 million net reduction in generation plant maintenance costs mainly related to Hoot Lake Plant being down for major maintenance in the third quarter of 2014.

A $1.0 million decrease in other operating and maintenance expenses, mostly vegetation control costs.

Offset by:

A $1.0 million increase in labor related benefit costs, mainly due to increases in pension and other benefit costs.

A $0.5 million increase in costs related to work performed for other regional transmission owners between the periods.

A $0.5 million increase in MISO transmission tariff charges related to increasing investments in regional transmission lines by other transmission owners including CapX2020 and MISO-designated MVP transmission projects.

The $0.4 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.

Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	52,460	$	55,536	$	(3,076	)		(5.5	)
Cost of Products Sold		40,961		42,314		(1,353	)		(3.2	)
Operating Expenses		5,094		5,704		(610	)		(10.7	)
Depreciation and Amortization		2,936		2,671		265			9.9
Operating Income	$	3,469	$	4,847	$	(1,378	)		(28.4	)

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

Revenues at BTD Manufacturing, Inc. (BTD), our metal parts stamping and fabrication company, decreased $4.3 million reflecting:

A $4.0 million decrease in sales to manufacturers of agricultural equipment related to continued softness in the agricultural industry.

A $1.0 million decrease in sales to manufacturers of oil and gas exploration and extraction equipment as a result of a reduction in drilling activity related to current low oil prices.

A $0.9 million decrease in revenue from sales of scrap metal due to a reduction in scrap metal prices between quarters.

A $0.4 million reduction in tooling revenues.

Offset by $2.0 million in sales at Impulse Manufacturing, Inc. (BTD-Georgia), acquired on September 1, 2015.

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased $1.2 million reflecting:

A $0.6 million increase in sales of custom products.

A $0.3 million increase in sales of horticultural containers.

A $0.3 million increase in sales of various other products to industrial customers.

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

Cost of products sold at BTD decreased $2.3 million, reflecting a $4.3 million decrease in costs, mainly labor and material, related to decreased sales, offset by $2.0 million in costs incurred at BTD-Georgia in September 2015 which includes $0.2 million in amortized costs related to the write up of finished goods inventory to fair market resale value on acquisition.

Cost of products sold at T.O. Plastics increased $0.9 million due to increases in material, labor and freight costs related to the increase in sales.

The decrease in Manufacturing segment operating expenses reflects a $0.5 million decrease in operating expenses at BTD, mainly incentive and benefit expenses, and a $0.1 million decrease in operating expenses at T.O. Plastics. Depreciation and amortization expense at BTD-Georgia in September 2015 was approximately $0.2 million.

Plastics

	Three Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	47,025	$	51,613	$	(4,588	)		(8.9	)
Cost of Products Sold		37,468		43,098		(5,630	)		(13.1	)
Operating Expenses		2,655		2,452		203			8.3
Depreciation and Amortization		914		825		89			10.8
Operating Income	$	5,988	$	5,238	$	750			14.3

The $4.6 million decrease in Plastics segment revenues is the result of a 9.4% decrease in the price per pound of polyvinyl chloride (PVC) pipe sold related to lower resin prices. Pounds of PVC pipe sold was flat between the quarters. The $5.6 million decrease in costs of products sold is due to a 13.6% decrease in the cost per pound of pipe sold mainly related to a decrease in material costs due to lower resin prices. The $0.2 million increase in Plastics operating expenses reflects an increase in labor and benefit costs.

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
	September 30,						%
(in thousands)	2015		2014		Change		Change
Operating Expenses	$	3,050	$	1,557	$	1,493		95.9
Depreciation and Amortization		101		28		73		260.7

The $1.5 million increase in corporate operating expenses includes:

A $1.2 million increase in health and casualty insurance costs.

A $0.3 million increase in other corporate costs.

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $2.4 million as a result of a $4.9 million increase in income from continuing operations before income taxes, a $0.2 million reduction in research and development tax credits and a $0.2 million increase in adjustments for uncertain tax positions between the third quarter of 2015 and the third 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 September 30, 2015 and 2014:

	Three Months Ended September 30,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	22,230		$	17,328
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		8,670			6,758
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,437	)		(1,362	)
Section 199 Domestic Production Activities Deduction		(362	)		(416	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(171	)		(186	)
Allowance for Funds Used During Construction (AFUDC) Equity		(144	)		(164	)
Investment Tax Credits		(143	)		(127	)
Research and Development Tax Credits		--			(219	)
Adjustment for Uncertain Tax Positions		281			119
Other Items – Net		39			(35	)
Income Tax Expense – Continuing Operations	$	6,521		$	4,156
Effective Income Tax Rate – Continuing Operations		29.3	%		24.0	%

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 increased 5.0% in the three months ended September 30, 2015 compared with the three months ended September 30, 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

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 $6.3 million in adjustments for working capital and other related items expected to be received in fourth quarter 2015. On February 28, 2015 we sold the assets of our former energy and electrical construction contractor (AEV, Inc.) for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015. We have recorded a $7.1 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 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 September 30, 2015 and 2014, include the operating results of Foley and AEV, Inc. and residual expenses from our former wind tower and waterfront equipment manufacturers:

	For the Three Months Ended September 30,
(in thousands)	2015			2014
Operating Revenues	$	--		$	45,846
Operating Expenses		420			42,034
Operating (Loss) Income		(420	)		3,812
Interest Charges		--			(1	)
Other Income		--			277
Income Tax (Benefit) Expense		(168	)		1,437
Net (Loss) Income from Operations		(252	)		2,653
Loss on Disposition Before Taxes		(108	)		--
Income Tax Benefit on Disposition		(43	)		--
Net Loss on Disposition		(65	)		--
Net (Loss) Income	$	(317	)	$	2,653

The above results for the three months ended September 30, 2015 include a net loss from operations of $0.2 million from Foley. Included in net income from operations for the three months ended September 30, 2014 are $1.3 million from AEV, Inc., $1.1 million for Foley and $0.2 million from our former waterfront equipment manufacturer related to a gain on the sale of residual assets.

Comparison of the Nine Months Ended September 30, 2015 and 2014

Consolidated operating revenues were $591.0 million for the nine months ended September 30, 2015 compared with
$605.9 million for the nine months ended September 30, 2014. Operating income was $79.5 million for the nine months ended September 30, 2015 compared with $74.7 million for the nine months ended September 30, 2014. The Company recorded diluted earnings per share from continuing operations of $1.15 for the nine months ended September 30, 2015 compared to $1.17 for the nine months ended September 30, 2014 and total diluted earnings per share of $1.19 for the nine months ended September 30, 2015 compared to $1.29 for the nine months ended September 30, 2014.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the nine month periods ended September 30, 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)	September 30, 2015		September 30, 2014
Operating Revenues:
Electric	$	80	$	81
Nonelectric		4		--
Cost of Products Sold		5		35
Other Nonelectric Expenses		79		46

Electric

	Nine Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Retail Sales Revenues	$	272,258	$	267,808	$	4,450			1.7
Wholesale Revenues – Company Generation		1,651		8,432		(6,781	)		(80.4	)
Net Revenue – Energy Trading Activity		187		268		(81	)		(30.2	)
Other Revenues		30,982		24,901		6,081			24.4
Total Operating Revenues	$	305,078	$	301,409	$	3,669			1.2
Production Fuel		29,906		49,754		(19,848	)		(39.9	)
Purchased Power – System Use		62,101		48,971		13,130			26.8
Other Operation and Maintenance Expenses		107,929		107,742		187			0.2
Depreciation and Amortization		33,391		32,722		669			2.0
Property Taxes		10,324		9,536		788			8.3
Operating Income	$	61,427	$	52,684	$	8,743			16.6
Electric kwh Sales (in thousands)
Retail kwh Sales		3,437,261		3,465,371		(28,110	)		(0.8	)
Wholesale kwh Sales – Company Generation		66,592		189,322		(122,730	)		(64.8	)
Wholesale kwh Sales – Purchased Power Resold		5,547		17,266		(11,719	)		(67.9	)
Heating Degree Days		3,791		4,820		(1,029	)		(21.3	)
Cooling Degree Days		482		375		107			28.5

The $4.5 million increase in retail revenue includes:

A $6.8 million increase in ECR rider revenues related to earning a return in North Dakota and Minnesota on increasing amounts invested in the AQCS at Big Stone Plant, earning a return on the Hoot Lake Plant MATS project in North Dakota beginning in 2015, 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 Hoot Lake Plant MATS projects.

A $1.4 million increase in revenues recoverable under CIP riders related to an increase in CIP incentives awarded for 2014 program results as well as increases in CIP accrued incentives and recoverable expenditures in 2015.

Offset by:

A $2.5 million decrease in revenues related to the 0.8% decrease in retail kwh sales mainly resulting from milder weather during the first nine months of 2015.

A $1.2 million decrease in Transmission Cost Recovery (TCR) rider revenues in Minnesota related to the impact of higher MISO transmission tariff revenues in 2015 on Minnesota TCR rider revenues.

Wholesale electric revenues from company-owned generation decreased $6.8 million as a result of a 64.8% reduction in wholesale kwh sales combined with a 44.3% decrease in revenue per wholesale kwh sold. The decreases in wholesale kwh sales and prices were driven by decreased wholesale market demand resulting from milder weather in the first half of 2015. Also, OTP had fewer resources available for selling into the wholesale market. Big Stone Plant was off line from March through July of 2015 for an extended maintenance outage that required off-site turbine blade replacements and repairs. Coyote Station has been operating at reduced load since December 2014 due to ongoing repairs related to a boiler feed pump failure and ensuing fire. Hoot Lake Plant has been curtailed in 2015 due to low market prices for electricity, which was a factor contributing to a strategic decision to shut down Hoot Lake Plant’s Unit 3 for preventative maintenance in September 2015. Generation from company-owned wind turbines was down 4.9% from the first nine months of 2014 due to icing, scheduled repairs and lower average wind speeds in the first half of 2015. The decrease in wholesale prices for electricity is due, in part, to lower prices for natural gas used in the generation of electricity in the first nine months of 2015 compared with the first nine months of 2014.

Other electric revenues increased $6.1 million as a result of a $6.9 million increase in MISO transmission tariff revenues related to increased investment in regional transmission projects including returns on and recovery of CapX2020 and MISO designated MVP investment costs and operating expense, offset by a $0.8 million decrease related to reduced steam sales to an ethanol plant next to Big Stone Plant as a result of Big Stone Plant being down for extended maintenance in 2015.

Production fuel costs decreased $19.8 million as a result of a 42.0% 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 $13.1 million due to a 62.0% increase in kwhs purchased, partially offset by a 21.7% 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 due to milder weather in the first half of 2015 in combination with lower prices for natural gas used in the generation of electricity.

Electric operating and maintenance expenses increased $0.2 million reflecting:

A $3.0 million increase in MISO transmission tariff charges related to increasing investments by other transmission owners in regional CapX2020 and MISO-designated MVP transmission projects.

A $1.9 million increase in labor related benefit costs, mainly related to increases in pension and other benefit costs.

Offset by:

A $2.8 million net reduction in generation plant operating and maintenance costs mainly related to two plants, Hoot Lake Plant and Coyote Station, being down for major maintenance in 2014 and only one plant, Big Stone Plant, being down for major maintenance in 2015. Although kwh generation has decreased for all three plants in 2015, work done on the plants in 2014 was more operating and maintenance in nature while more capital projects have been completed in 2015. Also, with the plants generating fewer kwhs in 2015, operating costs have been lower in 2015.

A $1.0 million reduction in travel related expenses related to an increase in vehicle usage on capital projects and a decrease in vehicle maintenance and operating expenses.

A $0.6 million increase in capitalized administrative and general expenses in 2015 due to more time being spent on capital projects.

An expense of $0.3 million recorded in June 2014 related to OTP not earning a return on the deferred recovery of the Minnesota share of Big Stone II abandoned transmission plant costs. No comparable expense was recorded in 2015.

Depreciation expense increased $0.7 million as a result of increased investment in transmission, distribution and general plant placed in service in 2014 and 2015.

The $0.8 million increase in property tax expense is 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.

Manufacturing

	Nine Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	160,492	$	164,341	$	(3,849	)		(2.3	)
Cost of Products Sold		126,185		125,698		487			0.4
Operating Expenses		16,256		16,029		227			1.4
Depreciation and Amortization		8,161		7,941		220			2.8
Operating Income	$	9,890	$	14,673	$	(4,783	)		(32.6	)

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

Revenues at BTD decreased $6.7 million reflecting:

A $6.6 million decrease in sales to manufacturers of oil and gas exploration and extraction equipment as a result of a reduction in drilling activity related to current low oil prices.

A $2.2 million decrease in sales of scrap metal due to a reduction in scrap metal prices and a reduction in scrap volume related to lower production and sales volumes between periods.

Offset by $2.0 million in sales at BTD-Georgia, acquired on September 1, 2015.

Revenues at T.O. Plastics increased $2.9 million reflecting:

A $1.3 million increase in sales of horticultural containers.

A $1.1 million increase in sales of custom products.

A $0.5 million increase in sales of various other products to industrial customers.

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

Cost of products sold at BTD decreased $2.1 million, reflecting a $4.1 million decrease in costs mainly due to reductions in labor, material and direct production costs related to the reduction in sales to manufacturers of oil and gas exploration and extraction equipment, offset by $2.0 million in costs incurred at BTD-Georgia in September 2015 which includes $0.2 million in amortized costs related to the write up of finished goods inventory to fair market resale value on acquisition.

Cost of products sold at T.O. Plastics increased $2.6 million due to increases in material, labor and freight costs related to the increase in sales at T.O. Plastics.

The increase in Manufacturing segment operating expenses reflects $0.2 million in operating expenses incurred at BTD-Georgia in September 2015. Depreciation and amortization expense at BTD-Georgia in September 2015 was approximately $0.2 million.

Plastics

	Nine Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Operating Revenues	$	125,531	$	140,186	$	(14,655	)		(10.5	)
Cost of Products Sold		98,732		113,838		(15,106	)		(13.3	)
Operating Expenses		7,350		6,994		356			5.1
Depreciation and Amortization		2,625		2,544		81			3.2
Operating Income	$	16,824	$	16,810	$	14			0.1

The $14.7 million decrease in Plastics segment revenues is the result of a 5.6% decrease in pounds of PVC pipe sold in combination with a 5.1% decrease in the price per pound of pipe sold. The decrease in sales are due in part to delayed purchases related to falling resin prices and in part to reduced demand in the region of the United States between the Mississippi River and the Rocky Mountain states, especially in Texas where soft markets were exacerbated by severe spring flooding. The $15.1 million decrease in costs of products sold is due to the decrease in sales volume in combination with an 8.1% decrease in the cost per pound of pipe sold mainly related to a decrease in material costs due to lower resin prices. The $0.4 million increase in operating expenses was mainly related to increased wage and benefit costs.

Corporate

	Nine Months Ended
	September 30,							%
(in thousands)	2015		2014		Change			Change
Operating Expenses	$	8,530	$	9,403	$	(873	)		(9.3	)
Depreciation and Amortization		160		89		71			79.8

The $0.9 million decrease in corporate operating expenses includes:

A $2.9 million reduction in airplane operating lease expense related to the early termination of an airplane lease in the second quarter of 2014, as divestitures had reduced the need for the airplane. The cost to terminate the lease early was approximately $2.5 million or a net-of-tax impact on diluted earnings per share of ($0.04).

offset by:

A $1.9 million increase in labor and benefit costs mainly due to increased health insurance costs.

A $0.2 million increase in costs related to leadership development and leadership succession.

Interest Charges

The $1.3 million increase in interest charges in the nine months ended September 30, 2015 compared with the nine months ended September 30, 2014 is mainly due to 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. OTP used a portion of the proceeds from the issuance of the Series A and B Senior Unsecured Notes referenced above to retire OTP’s $40.9 million unsecured term loan and repay $82.5 million of short-term debt then outstanding under the OTP Credit Agreement.

Other Income

The $1.4 million decrease in other income in the nine months ended September 30, 2015 compared with the nine months ended September 30, 2014, includes:

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 half of 2015.

A $0.3 million reduction in other income at OTP related to reductions in AFUDC and carrying charges earned on funds invested in Minnesota conservation improvement programs prior to recovery, in alignment with the decrease in short-term borrowing rates.

A $0.2 million reduction in corporate owned life insurance cash surrender value increases.

Income Taxes – Continuing Operations

The $1.8 million increase in income tax expense - continuing operations for the nine months ended September 30, 2015 compared with the nine months ended September 30, 2014 includes: (1) a $0.8 million increase in income tax expense related to a $2.1 million increase in income from continuing operations before income taxes, (2) a $0.3 million decrease in federal PTC’s earned, (3) a $0.3 million reduction related to corporate owned life insurance, (4) a $0.2 million increase in adjustments for uncertain tax positions, and (5) a $0.2 million reduction in research and development tax credits. 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 nine month periods ended September 30, 2015 and 2014:

	Nine Months Ended September 30,
(in thousands)	2015			2014
Income Before Income Taxes – Continuing Operations	$	57,749		$	55,639
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		22,522			21,699
Increases (Decreases) in Tax from:
Federal PTCs		(5,147	)		(5,478	)
Section 199 Domestic Production Activities Deduction		(1,087	)		(1,123	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(637	)		(637	)
Employee Stock Ownership Plan Dividend Deduction		(514	)		(568	)
Investment Tax Credits		(428	)		(380	)
AFUDC Equity		(369	)		(461	)
Corporate Owned Life Insurance		(39	)		(328	)
Research and Development Tax Credits		--			(219	)
Adjustment for Uncertain Tax Positions		367			119
Other Items – Net		(66	)		178
Income Tax Expense – Continuing Operations	$	14,602		$	12,802
Effective Income Tax Rate – Continuing Operations		25.3	%		23.0	%

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 6.1% due to icing, scheduled repairs and lower average wind speed in the first nine months of 2015 compared with the first nine months of 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

On April 30, 2015 we sold Foley for $12.0 million in cash, plus $6.3 million in adjustments for working capital and other related items expected to be received in fourth quarter 2015. On February 28, 2015 we sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million in adjustments for working capital and fixed assets received in October 2015. We have recorded a $7.1 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 nine-month periods ended September 30, 2015 and 2014, include the operating results of Foley and AEV, Inc. and residual expenses from our former wind tower and waterfront equipment manufacturers:

	For the Nine Months Ended September 30,
(in thousands)	2015			2014
Operating Revenues	$	24,623		$	111,599
Operating Expenses		31,770			105,153
Goodwill Impairment Charge		1,000			--
Operating (Loss) Income		(8,147	)		6,446
Interest Charges		--			--
Other (Deductions) Income		(42	)		579
Income Tax (Benefit) Expense		(2,873	)		2,614
Net (Loss) Income from Operations		(5,316	)		4,411
Gain on Disposition Before Taxes		11,425			--
Income Tax Expense on Disposition		4,493			--
Net Gain on Disposition		6,932			--
Net Income	$	1,616		$	4,411

The above results for the nine months ended September 30, 2015 include net losses from operations of $4.1 million from Foley, $0.8 million from AEV, Inc. and $0.6 million from our former waterfront equipment manufacturer mainly related to the settlement of a warranty claim in the second quarter of 2015 and net income of $0.2 million from our former wind tower manufacturer related to a reduction in warranty reserves for expired warranties. The above results for the nine months ended September 30, 2014 include net income from operations of $2.4 million from Foley, $1.8 million from AEV, Inc. and $0.2 million from our former waterfront equipment manufacturer related to a gain on the sale of residual assets.

Financial Position

The following table presents the status of our lines of credit as of September 30, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on September 30, 2015		Restricted due to Outstanding Letters of Credit		Available on September 30, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	75,881	$	--	$	74,119	$	138,872
OTP Credit Agreement		170,000		11,071		310		158,619		169,440
Total	$	320,000	$	86,952	$	310	$	232,738	$	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 provided by operating activities from continuing operations was $81.8 million for the nine months ended September 30, 2015 compared with $68.3 million for the nine months ended September 30, 2014. Contributing to the $13.5 million increase in cash provided by continuing operations between the periods were a $10.0 million decrease in discretionary contributions to the Company’s pension plan and changes in non-cash items affecting net income from continuing operations, including a $5.7 million change in noncurrent liabilities and deferred credits mainly related to changes in long-term benefit costs, a $1.1 million change in deferred taxes and other long-term assets and a $1.0 million increase in depreciation expense, offset by a $4.4 million increase in cash used for working capital items. The increase in cash used for working capital items between the periods includes a $14.8 million increase in cash used for payables and other current liabilities, mostly in our Plastics segment, offset by a $10.3 million reduction in cash used for inventory in our Plastics segment between the periods. In the first nine months of 2014, increasing resin costs contributed to a $2.7 million increase in inventory in our Plastics segment, while declining resin costs and finished goods inventory levels have contributed to a $7.6 million decrease in our Plastics segment inventories in the first nine months of 2015.

In continuing operations, net cash used in investing activities was $150.5 million for the nine months ended September 30, 2015 compared with $124.5 million for the nine months ended September 30, 2014. The purchase of the assets of BTD-Georgia for $30.8 million on September 1, 2015 was the main factor contributing to the $26.0 million increase in cash used in investing activities of continuing operations between the periods. The $8.4 million decrease in cash used for capital expenditures includes an $18.8 million reduction in capital expenditures at OTP as several major projects wound down in 2015, including two CapX2020 transmission line projects and the new AQCS at Big Stone Plant, partially offset by a $9.9 million increase in cash used for capital expenditures in our Manufacturing segment, mainly at BTD as it moves forward with its project to expand and realign its Minnesota production and warehouse facilities.

Investing activities of discontinued operations in the first nine months of 2015 includes $21.3 million in cash proceeds from the sale of AEV, Inc. and $11.4 million from the sale of Foley, 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 of continuing operations was $49.5 million in the nine months ended September 30, 2015 compared with $75.7 million for the nine months ended September 30, 2014. Net cash provided by financing activities in the first nine months of 2015 includes $76.1 million in short-term borrowings used to fund a portion of our capital expenditures and the acquisition of BTD-Georgia. Net cash proceeds of $11.0 million from the issuance of common stock under our At-the-Market offering program and various stock purchase and dividend reinvestment plans were also used to fund a portion of our capital expenditures. See note 6 to the Company’s consolidated financial statements for further information on stock issuances and retirements in the first nine months of 2015. Cash used for common stock dividend payments totaled $34.6 million in the first nine months of 2015.

Net cash provided by financing activities in the nine months ended September 30, 2014 of $75.7 million 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. Financing activities in the first nine months of 2014 also include:

The payment of $33.0 million in common stock dividends.

The borrowing of $39.0 million under the Otter Tail Corporation Credit Agreement to fund the working capital needs of our manufacturing and infrastructure companies.

$12.9 million in net cash proceeds from the issuance of common stock. In 2014, we began issuing common shares to meet the requirements of our dividend reinvestment and share purchase plan, employee stock ownership plan and employee stock purchase plan, rather than purchasing shares in the open market. In the second quarter of 2014 we began issuing common shares using our At-the-Market offering program under our Distribution Agreement with J.P. Morgan Securities (JPMS).

CAPITAL REQUIREMENTS

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 $25.0 million in the first nine months 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 operating lease obligations increased $0.3 million in 2015, $2.4 million in 2016 and 2017, $0.7 million in 2018 and 2019 and $0.2 million beyond 2019 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, and as a result of a five-year extension of an operating lease in our Plastics segment beginning in October 2015. Our commitments under construction contracts increased $0.5 million for 2015, $8.0 million for 2016 and 2017 and $2.9 million for 2018 in connection with contracts for the construction of the Big Stone South to Ellendale transmission line project.

CAPITAL RESOURCES

On May 11, 2015 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, 2018. On May 11, 2015, we entered into a Distribution Agreement with 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 third quarter of 2015 we received proceeds of $1,566,000 net of $20,000 paid to JPMS from the issuance of 57,769 shares under this program.

Short-Term Debt

The following table presents the status of our lines of credit as of September 30, 2015 and December 31, 2014:

(in thousands)	Line Limit		In Use on September 30, 2015		Restricted due to Outstanding Letters of Credit		Available on September 30, 2015		Available on December 31, 2014
Otter Tail Corporation Credit Agreement	$	150,000	$	75,881	$	--	$	74,119	$	138,872
OTP Credit Agreement		170,000		11,071		310		158,619		169,440
Total	$	320,000	$	86,952	$	310	$	232,738	$	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 October 29, 2015 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2019 to October 29, 2020. 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 October 29, 2015 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2019 to October 29, 2020. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

Long-Term Debt

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.”

Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of September 30, 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 September 30, 2015 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement was 3.62 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 September 30, 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 3.55 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 September 30, 2015 our ratio of interest-bearing debt to total capitalization was 0.49 to 1.00 on a consolidated basis and 0.48 to 1.00 for OTP.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $5.5 million, but our line of credit borrowing limits are only restricted by $0.3 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 reaffirming our consolidated diluted earnings per share guidance for 2015 to be in the middle to upper end of the range of $1.50 to $1.65. This guidance reflects the current mix of businesses owned by us and is based on current tax laws. 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. Should the federal government change current tax law before the end of 2015, the corporation’s consolidated earnings guidance could be negatively impacted in the range of $0.02 to $0.04 per share.

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


	2014 Actual			Initial 2015 Guidance February 9, 2015						2015 Guidance August 3, 2015						2015 Guidance November 2, 2015
Diluted Earnings Per Share				Low			High			Low			High			Low			High
Electric	$	1.19		$	1.26		$	1.29		$	1.23		$	1.26		$	1.26		$	1.29
Manufacturing	$	0.25		$	0.37		$	0.41		$	0.21		$	0.25		$	0.15		$	0.19
Plastics	$	0.33		$	0.25		$	0.29		$	0.29		$	0.33		$	0.31		$	0.35
Corporate	$	(0.22	)	$	(0.23	)	$	(0.19	)	$	(0.23	)	$	(0.19	)	$	(0.22	)	$	(0.18	)
Total – Continuing Operations	$	1.55		$	1.65		$	1.80		$	1.50		$	1.65		$	1.50		$	1.65
Expected Return on Equity											9.5	%		10.4	%		9.5	%		10.4	%

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

We expect 2015 net income from our Electric segment to be improved from our previous guidance and to be better than 2014 net income due to stronger results during the first nine months of 2015. Items affecting the increase over 2014 net income 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.

Increased sales to pipeline customers.

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

offset by:

Lower retail sales due to milder than normal weather in the first nine months of 2015.

Higher than expected claim costs and more participants associated with the long-term disability plans.

An increase in coal plant reagent costs that were determined unrecoverable under rider by the Minnesota Public Utilities Commission in March 2015.

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 under OTP’s credit agreement.

We expect 2015 net income guidance from our Manufacturing segment to be below our previous segment guidance for 2015 and below 2014 net income due to:

Continued softness in the agriculture, energy, mining and oil and gas equipment end markets served by BTD’s customers, declining commodity prices for scrap metal and increased costs of manufacturing due to lower productivity.

Expectations for earnings from T.O. Plastics in 2015 have also been reduced from previous guidance due to recent reductions in sales forecasts as certain end-market customers of T.O. Plastics are experiencing delayed or unsuccessful product launches and certain products are now being produced in house by customers.

Backlog for the manufacturing companies of approximately $45 million for 2015 compared with $50 million one year ago.

We are raising our guidance for 2015 net income from our Plastics segment based on strong results during the first nine months of 2015 which are in line with 2014 results for the same time frame.

We expect corporate costs in 2015 to be in line with, or slightly lower than, 2014 costs.

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, 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. With the sale of Foley in April 2015 we no longer own any construction businesses applying percentage-of-completion accounting and, subsequent to the sale of Foley, our results of operations are no longer subject to adjustments related to changes in estimates of projected costs used to determine expected profits and progress toward completion on construction jobs in progress. There were no other material changes in critical accounting policies or estimates during the quarter ended September 30, 2015.

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 each of Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 and Part II, Item 1A of our Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2015, 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.

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 September 30, 2015 we had exposure to market risk associated with interest rates because we had $75.9 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 $11.1 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 September 30, 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 September 30, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts.

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 September 30, 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 September 30, 2015.

During the fiscal quarter ended September 30, 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 as updated in Part II, Item 1A of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.

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 or vested for incentive awards in July 2015 under the Company's 1999 and 2014 Stock Incentive Plans:

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
July 2015		6,515	$	26.78
August 2015		--		--
September 2015		--		--
Total		6,515

Item 6. Exhibits

4.1

Third Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 3, 2015).

4.2

Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 3, 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 September 30, 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: November 9, 2015

EXHIBIT INDEX

Exhibit Number	Description

4.1	Third Amendment to Third Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 3, 2015).

4.2	Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 29, 2015, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 3, 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 September 30, 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.