Otter Tail Corp - FORM 10-Q - November 7, 2016

Attached files

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EX-32.1 - EXHIBIT 32.1 - Otter Tail Corp	t1600694_ex32-1.htm
EX-32.2 - EXHIBIT 32.2 - Otter Tail Corp	t1600694_ex32-2.htm
EX-31.2 - EXHIBIT 31.2 - Otter Tail Corp	t1600694_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Otter Tail Corp	t1600694_ex31-1.htm
EX-10.1 - EXHIBIT 10.1 - Otter Tail Corp	t1600694_ex10-1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended

September 30, 2016

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, 2016 – 39,268,205 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.

Item 1.	Financial Statements

	Consolidated Balance Sheets – September 30, 2016 and December 31, 2015 (not audited)	2 & 3

	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2016 and 2015 (not audited)	4

	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2016 and 2015 (not audited)	5

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2016 and 2015 (not audited)	6

	Condensed Notes to Consolidated Financial Statements (not audited)	7-32

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32-52

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52

Item 4.	Controls and Procedures	52

Part II. Other Information

Item 1.	Legal Proceedings	53

Item 1A.	Risk Factors	53

Item 6.	Exhibits	53

Signatures		54

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	September 30, 2016		December 31, 2015

Assets

Current Assets
Cash and Cash Equivalents	$	—	$	—
Accounts Receivable:
Trade—Net		69,556		62,974
Other		7,082		9,073
Inventories		80,848		85,416
Unbilled Revenues		14,882		17,869
Income Taxes Receivable		—		4,000
Regulatory Assets		19,958		18,904
Other		11,139		8,453
Assets of Discontinued Operations		249		—
Total Current Assets		203,714		206,689

Investments		8,065		8,284
Other Assets		33,707		32,784
Goodwill		37,572		39,732
Other Intangibles—Net		15,291		15,673
Regulatory Assets		118,123		127,707

Plant
Electric Plant in Service		1,842,931		1,820,763
Nonelectric Operations		215,074		201,343
Construction Work in Progress		143,999		79,612
Total Gross Plant		2,202,004		2,101,718
Less Accumulated Depreciation and Amortization		749,569		713,904
Net Plant		1,452,435		1,387,814

Total Assets	$	1,868,907	$	1,818,683

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	September 30, 2016			December 31, 2015

Liabilities and Equity

Current Liabilities
Short-Term Debt	$	37,173		$	80,672
Current Maturities of Long-Term Debt		85,490			52,422
Accounts Payable		77,704			89,499
Accrued Salaries and Wages		15,573			16,182
Accrued Taxes		12,635			14,827
Other Accrued Liabilities		16,050			15,416
Liabilities of Discontinued Operations		1,631			2,098
Total Current Liabilities		246,256			271,116

Pensions Benefit Liability		95,653			104,912
Other Postretirement Benefits Liability		49,718			48,730
Other Noncurrent Liabilities		25,857			23,854

Commitments and Contingencies (note 9)

Deferred Credits
Deferred Income Taxes		222,244			207,669
Deferred Tax Credits		23,264			24,506
Regulatory Liabilities		79,835			77,432
Other		8,604			11,595
Total Deferred Credits		333,947			321,202

Capitalization
Long-Term Debt—Net		460,757			443,846

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, 2016—39,224,553 Shares; 2015—37,857,186 Shares		196,123			189,286
Premium on Common Shares		329,288			293,610
Retained Earnings		134,884			126,025
Accumulated Other Comprehensive Loss		(3,576	)		(3,898	)
Total Common Equity		656,719			605,023

Total Capitalization		1,117,476			1,048,869

Total Liabilities and Equity	$	1,868,907		$	1,818,683

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)	2016		2015			2016		2015
Operating Revenues
Electric	$	102,712	$	100,538		$	313,615	$	304,998
Product Sales		94,463		99,485			293,284		286,019
Total Operating Revenues		197,175		200,023			606,899		591,017
Operating Expenses
Production Fuel - Electric		14,789		11,124			40,479		29,906
Purchased Power - Electric System Use		11,473		18,725			43,486		62,101
Electric Operation and Maintenance Expenses		36,207		32,648			115,206		107,929
Cost of Products Sold (depreciation included below)		75,405		78,428			228,993		224,912
Other Nonelectric Expenses		10,197		10,771			30,890		32,057
Depreciation and Amortization		18,314		15,141			55,128		44,337
Property Taxes - Electric		3,506		3,560			10,774		10,324
Total Operating Expenses		169,891		170,397			524,956		511,566
Operating Income		27,284		29,626			81,943		79,451
Interest Charges		8,026		7,730			23,996		23,175
Other Income		499		334			2,431		1,473
Income Before Income Taxes—Continuing Operations		19,757		22,230			60,378		57,749
Income Tax Expense—Continuing Operations		5,163		6,521			15,738		14,602
Net Income from Continuing Operations		14,594		15,709			44,640		43,147
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $14, ($168), $114 and ($2,873) for the respective periods		22		(252	)		171		(4,316	)
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 Income (Loss) from Discontinued Operations		22		(317	)		171		1,616
Net Income		14,616		15,392			44,811		44,763

Average Number of Common Shares Outstanding—Basic		38,832,659		37,575,413			38,316,324		37,417,283
Average Number of Common Shares Outstanding—Diluted		39,005,706		37,794,543			38,457,401		37,636,413

Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	0.38	$	0.42		$	1.17	$	1.15
Discontinued Operations		—		(0.01	)		—		0.05
	$	0.38	$	0.41		$	1.17	$	1.20
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	0.37	$	0.42		$	1.16	$	1.15
Discontinued Operations		—		(0.01	)		0.01		0.04
	$	0.37	$	0.41		$	1.17	$	1.19

Dividends Declared Per Common Share	$	0.3125	$	0.3075		$	0.9375	$	0.9225

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)	2016			2015			2016			2015
Net Income	$	14,616		$	15,392		$	44,811		$	44,763
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	)		—			(3	)		(3	)
(Losses) Gains Arising During Period		(35	)		6			65			1
Income Tax Benefit (Expense)		13			(2	)		(22	)		1
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		(25	)		4			40			(1	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		161			205			470			616
Income Tax Expense		(64	)		(82	)		(188	)		(247	)
Pension and Postretirement Benefit Plans – net-of-tax		97			123			282			369
Total Other Comprehensive Income		72			127			322			368
Total Comprehensive Income	$	14,688		$	15,519		$	45,133		$	45,131

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)	2016			2015
Cash Flows from Operating Activities
Net Income	$	44,811		$	44,763
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		—			(6,932	)
Net (Income) Loss from Discontinued Operations		(171	)		5,316
Depreciation and Amortization		55,128			44,337
Deferred Tax Credits		(1,242	)		(1,408	)
Deferred Income Taxes		14,924			12,244
Change in Deferred Debits and Other Assets		5,595			13,839
Discretionary Contribution to Pension Plan		(10,000	)		(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		5,999			4,345
Allowance for Equity/Other Funds Used During Construction		(605	)		(944	)
Change in Derivatives Net of Regulatory Deferral		—			(28	)
Stock Compensation Expense—Equity Awards		1,151			1,428
Other—Net		(73	)		(27	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(3,490	)		(14,020	)
Change in Inventories		4,766			5,721
Change in Other Current Assets		1,690			2,163
Change in Payables and Other Current Liabilities		(5,945	)		(17,490	)
Change in Interest and Income Taxes Receivable/Payable		2,538			(1,499	)
Net Cash Provided by Continuing Operations		115,076			81,808
Net Cash Used for Discontinued Operations		(333	)		(11,581	)
Net Cash Provided by Operating Activities		114,743			70,227
Cash Flows from Investing Activities
Capital Expenditures		(125,913	)		(115,321	)
Net Proceeds from Disposal of Noncurrent Assets		4,167			2,956
Purchase Price Adjustment (Payment) – BTD-Georgia Acquisition		1,500			(30,806	)
Cash Used for Investments and Other Assets		(3,161	)		(7,297	)
Net Cash Used in Investing Activities - Continuing Operations		(123,407	)		(150,468	)
Net Proceeds from Sale of Discontinued Operations		—			32,765
Net Cash Used in Investing Activities - Discontinued Operations		—			(1,769	)
Net Cash Used in Investing Activities		(123,407	)		(119,472	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(841	)		(1,236	)
Net Short-Term Debt (Repayments) Borrowings		(43,499	)		76,098
Proceeds from Issuance of Common Stock – net of Issuance Expenses		39,378			10,979
Payments for Retirement of Capital Stock		(104	)		(1,596	)
Proceeds from Issuance of Long-Term Debt		50,000			—
Short-Term and Long-Term Debt Issuance Expenses		(157	)		(7	)
Payments for Retirement of Long-Term Debt		(161	)		(149	)
Dividends Paid and Other Distributions		(35,952	)		(34,607	)
Net Cash Provided by Financing Activities – Continuing Operations		8,664			49,482
Net Cash Provided by Financing Activities – Discontinued Operations		—			321
Net Cash Provided by Financing Activities		8,664			49,803
Net Change in Cash and Cash Equivalents - Discontinued Operations		—			(10	)
Net Change in Cash and Cash Equivalents		—			548
Cash and Cash Equivalents at Beginning of Period		—			—
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, 2015. Because of seasonal and other factors, the earnings for the three- and nine-month periods ended September 30, 2016 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, 2015.

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, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. In the case of derivative instruments, such as Otter Tail Power Company’s (OTP) 2015 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.

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (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, 2016 and December 31, 2015:

September 30, 2016 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	4,408
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				3,506
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	764
Total Assets	$	764	$	7,914
Liabilities:
Other Accrued Liabilities:
Derivative Liabilities – Forward Gasoline Purchase Contracts			$	49
Total Liabilities			$	49

December 31, 2015 (in thousands)	Level 1		Level 2		Level 3
Assets:
Current Assets – Other:
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions	$	2,000
Investments:
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company			$	4,235
Corporate Debt Securities – Held by Captive Insurance Company				3,858
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		196
Total Assets	$	2,196	$	8,093
Liabilities:
Other Accrued Liabilities:
Derivative Liabilities – Forward Gasoline Purchase Contracts			$	199
Total Liabilities			$	199

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

Forward Gasoline Purchase Contracts – 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.

Government-Backed and Government-Sponsored Enterprises’ and Corporate 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.

Inventories

Inventories consist of the following:

	September 30,		December 31,
(in thousands)	2016		2015
Finished Goods	$	21,888	$	25,971
Work in Process		13,774		12,821
Raw Material, Fuel and Supplies		45,186		46,624
Total Inventories	$	80,848	$	85,416

Goodwill and Other Intangible Assets

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 operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information.

An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2015 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table summarizes changes to goodwill by business segment during 2016:

(in thousands)	Gross Balance December 31, 2015		Accumulated Impairments		Balance (net of impairments) December 31, 2015		Adjustments to Goodwill in 2016			Balance (net of impairments) September 30, 2016
Manufacturing	$	20,430	$	—	$	20,430	$	(2,160	)	$	18,270
Plastics		19,302		—		19,302		—			19,302
Total	$	39,732	$	—	$	39,732	$	(2,160	)	$	37,572

Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement.

The following table summarizes the components of the Company’s intangible assets at September 30, 2016 and December 31, 2015:

September 30, 2016 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,577	$	14,914	39-227 months
Covenant not to Compete		590		213		377	23 months
Total	$	23,081	$	7,790	$	15,291

December 31, 2015 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	21,681	$	6,714	$	14,967	48-236 months
Covenant not to Compete		620		69		551	32 months
Other Intangible Assets		639		543		96	9 months
Emission Allowances		59		NA		59	Expensed as used
Total	$	22,999	$	7,326	$	15,673

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2016		2015		2016		2015
Amortization Expense – Intangible Assets	$	348	$	282	$	1,103	$	770

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

(in thousands)		2016				2017				2018				2019				2020
Estimated Amortization Expense – Intangible Assets		$	1,436			$	1,330			$	1,264			$	1,133			$	1,099

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2016		2015
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	11,552	$	21,760

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 commenced with the initial delivery of coal to Coyote Station 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. If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. Coyote Station started taking delivery of coal and paying for coal and the accumulated development fees and capital charges under the LSA in May 2016. OTP’s 35% share of the unrecovered development period costs, development fees and capital charges incurred by CCMC through September 30, 2016 is $61.7 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, 2016 could be as high as $61.7 million.

New Accounting Standards

ASU 2014-09—In May 2014, the FASB issued ASU No. 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. As of September 30, 2016 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. 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 No. 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 is effective for interim and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet. The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance sheet and of the associated reclassification of unamortized line of credit issuance costs are shown in the following table:

(in thousands)	Previously Stated		Adjustments			Restated
Other Assets	$	31,108	$	1,676		$	32,784
Unamortized Debt Expense		3,897		(3,897	)		—
Total Assets		1,820,904		(2,221	)		1,818,683

Current Liabilities
Current Maturities of Long-Term Debt		52,544		(122	)		52,422
Total Current Liabilities		271,238		(122	)		271,116
Capitalization
Long-Term Debt—Net		445,945		(2,099	)		443,846
Total Capitalization		1,050,968		(2,099	)		1,048,869
Total Liabilities and Equity		1,820,904		(2,221	)		1,818,683

ASU 2015-11—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.

ASU 2016-02—In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous leases guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

ASU 2016-09—In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is intended to improve and simplify accounting and reporting requirements related to stock-based compensation programs. The amendments in ASU 2016-09 will change how companies account for certain aspects of share-based payments to employees. Under the updated standard, excess tax benefits related to vested awards recognized in stockholders' equity under prior guidance will be recognized in the income statement when the awards vest, and the level of shares that can be withheld to cover income taxes on awards to satisfy statutory income tax withholding obligations without triggering liability classification has been increased. The amendments in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any interim or annual period. The Company is currently evaluating the impact this standard will have on its consolidated financial statements, but does not expect it to be material.

2. Business Combinations and Segment Information

Business Combinations

On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company.

Below is condensed balance sheet information disclosing the final allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia:

(in thousands)
Assets:
Current Assets	$	4,906
Goodwill		6,083
Other Intangible Assets		6,270
Other Amortizable Assets		1,380
Fixed Assets		13,649
Total Assets	$	32,288
Liabilities:
Current Liabilities	$	2,971
Lease Obligation		11
Total Liabilities	$	2,982
Cash Paid	$	29,306

The assignment of asset values is based on the final purchase price. In the fourth quarter of 2015, the Company elected to early adopt ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The purchase price adjustment agreed to in June 2016 resulted in a $2.2 million reduction to the value of acquired goodwill, a $0.8 million increase in the fair value of acquired customer relationships and a $0.1 million increase in acquired liabilities. The changes in the value of customer relationships had an insignificant impact on the Company’s consolidated net income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015.

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 a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907.

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

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

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

No single customer accounted for over 10% of the Company’s consolidated revenues in 2015. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5% and 98.2% of its operating revenues for the respective three-month periods ended September 30, 2016 and 2015, and 98.6% and 97.2% of its operating revenues for the respective nine-month periods ended September 30, 2016 and 2015.

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-month periods ended September 30, 2016 and 2015 and total assets by business segment as of September 30, 2016 and December 31, 2015 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Electric	$	102,723		$	100,567		$	313,642		$	305,078
Manufacturing		52,171			52,460			170,443			160,492
Plastics		42,292			47,025			122,841			125,531
Intersegment Eliminations		(11	)		(29	)		(27	)		(84	)
Total	$	197,175		$	200,023		$	606,899		$	591,017

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2016		2015		2016		2015
Electric	$	6,304	$	6,069	$	18,744	$	18,273
Manufacturing		974		900		2,972		2,578
Plastics		273		257		796		782
Corporate and Intersegment Eliminations		475		504		1,484		1,542
Total	$	8,026	$	7,730	$	23,996	$	23,175

Income Tax Expense—Continuing Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Electric	$	4,730		$	4,761		$	11,262		$	9,995
Manufacturing		182			855			2,992			2,516
Plastics		1,577			2,206			5,206			6,159
Corporate		(1,326	)		(1,301	)		(3,722	)		(4,068	)
Total	$	5,163		$	6,521		$	15,738		$	14,602

Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Electric	$	12,513		$	12,921		$	34,199		$	34,351
Manufacturing		1,246			1,714			6,108			4,810
Plastics		2,346			3,534			7,983			9,919
Corporate		(1,511	)		(2,460	)		(3,650	)		(5,933	)
Discontinued Operations		22			(317	)		171			1,616
Total	$	14,616		$	15,392		$	44,811		$	44,763

Identifiable Assets

	September 30,		December 31,
(in thousands)	2016		2015
Electric	$	1,575,790	$	1,520,887
Manufacturing		168,705		173,860
Plastics		86,731		81,624
Corporate		37,432		42,312
Discontinued Operations		249		—
Total	$	1,868,907	$	1,818,683

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2016 and 2015.

Major Capital Expenditure Projects

Big Stone Plant Air Quality Control System (AQCS)—OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial operation on December 29, 2015. OTP’s capitalized cost of the project, excluding Allowance for Funds Used During Construction (AFUDC), as of September 30, 2016 was approximately $199.3 million.

Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—OTP has invested approximately $81.5 million and has a 14.2% ownership interest in the jointly owned assets of this 240-mile transmission line, and owns 100% of certain assets of the project. 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 $26.3 million and has a 4.8% ownership interest in this 250-mile transmission line. The MISO approved 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 of MVPs 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 345 kV transmission line, currently under construction, will extend approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN, a subsidiary of Xcel Energy Inc., jointly developed this project with obligations to have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the third quarter of 2015 and the line is expected to be in service in fall 2017. OTP’s capitalized cost of this project as of September 30, 2016 was approximately $56.4 million, which includes assets that are 100% owned by OTP.

The Big Stone South–Ellendale MVP—This 345 kV transmission line will extend 160 to 170 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU) with obligations of having equal ownership interest in the transmission line portion of the project. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized cost of this project as of September 30, 2016 was approximately $39.8 million, which includes assets that are 100% owned by OTP.

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.

Minnesota

2016 General Rate Case—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On February 26, 2016 the Minnesota Department of Commerce (MNDOC) concluded that the filing was complete. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills, as modified and subject to refund. The request and interim rate information is detailed in the table below:

	Annualized or			Actual Through September 30, 2016
($ in thousands)	Test Year			Three Months Ended		Nine Months Ended
Revenue Increase Requested	$	19,296
Increase Percentage Requested		9.80	%
Jurisdictional Rate Base	$	483,000
Interim Revenue Increase (subject to refund)	$	16,816		$	3,818	$	6,875

The major components of the requested rate increase are summarized below:

Revenue Requirement Deficiency Cost Factors (in thousands)	2016 Test Year Allocation
Increased Rate Base	$	10,000
Increased Expenses		7,700
Other		1,596
Total Requested Revenue Increase	$	19,296
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset		(2,480	)
Approved Interim Revenue Increase (subject to refund)	$	16,816

The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the MNDOC included a recommendation for an 8.86% allowed rate of return on equity and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. The deadline for submission of surrebuttal testimony was September 28, 2016. Hearings before the Administrative Law Judge (ALJ) occurred on October 13, 14 and 17, 2016.

Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $2.3 million as of September 30, 2016.

Expected dates for next steps in the procedural schedule:

Report of ALJ ─ January 5, 2017

Final order ─ March 16, 2017

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. OTP requested approval for recovery of its 2014 MNCIP financial incentive and 2014 program costs not included in base rates from the MPUC in an

April 1, 2015 filing. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million along with an updated surcharge with an effective date of October 1, 2015. Based on results from the 2015 MNCIP program year, OTP recognized a financial incentive of $4.2 million in 2015. The 2015 MNCIP program resulted in a 39% increase in energy savings compared to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued an order approving OTP’s request with an effective date of October 1, 2016.

The MNDOC has proposed changes to the MNCIP financial incentive mechanism. On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism.

The MNDOC opened an additional docket to investigate how investor-owned utilities calculate their avoided costs pertaining to generation capacity, energy, transmission and distribution. Avoided costs are the basis of MNCIP program benefits which going forward will establish OTP’s financial incentive. On May 23, 2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but is requiring Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019 with results to be submitted to the MNDOC by January 31, 2017.

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. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016. OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC granted an extension to the MNDOC to file initial comments in this docket until November 1, 2016.

Environmental Cost Recovery Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota Environmental Cost Recovery (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. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014 with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014 annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and granted an extension to the MNDOC to file initial comments in this docket until November 1, 2016.

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) rider 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 along with a return on investment. On March 25, 2015 the NDPSC approved OTP’s 2014 annual update to the NDRRA rider, including a change in rate design from an amount per kilowatt-hour consumed to a percentage of a customer’s bill, with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal

Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%.

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. The NDPSC approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2 million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for 2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the current true-up over-collection balance be spread over the next two years for purposes of reducing the volatility of the rates from year to year. An informal hearing is scheduled for November 30, 2016.

Environmental Cost Recovery Rider—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. 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. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project costs.

On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.

Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its Fuel Clause Adjustment (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 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. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February 12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an 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. The SDPUC approved

the request on October 15, 2015 with an effective date of November 1, 2015. On August 31, 2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC approved the request on October 26, 2016 with an effective date of November 1, 2016. This year’s lower revenue requirement is a result of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS.

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
Rate Rider (in thousands)	2016		2015		2016		2015
Minnesota
Conservation Improvement Program Costs and Incentives¹	$	2,839	$	1,970	$	7,554	$	5,508
Transmission Cost Recovery		779		1,141		4,188		3,968
Environmental Cost Recovery		3,127		2,565		9,362		7,722
North Dakota
Renewable Resource Adjustment		2,170		2,073		6,151		5,898
Transmission Cost Recovery		1,950		1,565		6,155		4,912
Environmental Cost Recovery		2,762		2,312		8,344		7,233
South Dakota
Transmission Cost Recovery		335		267		1,397		911
Environmental Cost Recovery		691		461		1,951		1,484
Conservation Improvement Program Costs and Incentives		135		234		418		464

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.

Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.

On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the 12.38% ROE used in MISO’s transmission rates over a 15-month period ending in February 2015 to a proposed 9.15%. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67% over a 15-month period ending in May 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. The FERC is expected to issue its order in the spring of 2017.

Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded a reduction in revenue of $0.1 million in the three-month period ended September 30, 2015, and $1.3 million and $0.9 million in the nine-month periods ended September 30, 2016 and 2015, respectively, and has a $2.4 million liability on its balance sheet as of September 30, 2016, representing OTP’s best estimate of a refund obligation that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. As a result of the FERC order issued on September 28, 2016 in the first complaint proceeding establishing an allowed ROE of 10.32%, no additional liability was recorded in the third quarter of 2016.

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, 2016						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits¹	$	7,439	$	94,671	$	102,110	see below
Deferred Marked-to-Market Losses¹		4,063		7,483		11,546	51 months
Conservation Improvement Program Costs and Incentives²		4,286		3,079		7,365	24 months
Accumulated ARO Accretion/Depreciation Adjustment¹		—		6,031		6,031	asset lives
Big Stone II Unrecovered Project Costs – Minnesota¹		619		2,444		3,063	55 months
North Dakota Renewable Resource Rider Accrued Revenues²		1,608		826		2,434	18 months
Debt Reacquisition Premiums¹		349		1,278		1,627	192 months
Deferred Income Taxes¹		—		1,157		1,157	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery¹		748		—		748	12 months
Big Stone II Unrecovered Project Costs – South Dakota²		101		567		668	80 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues²		—		544		544	27 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up²		474		43		517	27 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues²		225		—		225	12 months
Minnesota Renewable Resource Rider Accrued Revenues²		46		—		46	12 months
Total Regulatory Assets	$	19,958	$	118,123	$	138,081
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	77,603		77,603	asset lives
Refundable Fuel Clause Adjustment Revenues		2,301		—		2,301	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		638		758		1,396	24 months
Minnesota Transmission Cost Recovery Rider Accrued Refund		1,356		—		1,356	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		712		385		1,097	19 months
Deferred Income Taxes		—		918		918	asset lives
Minnesota Environmental Cost Recovery Rider Accrued Refund		370		—		370	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		296		—		296	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		256		—		256	12 months
Other		5		91		96	207 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		—		80		80	27 months
Total Regulatory Liabilities	$	5,934	$	79,835	$	85,769
Net Regulatory Asset Position	$	14,024	$	38,288	$	52,312

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, 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	$	7,439	$	99,293	$	106,732	see below
Deferred Marked-to-Market Losses¹		4,063		10,530		14,593	60 months
Conservation Improvement Program Costs and Incentives²		4,411		4,266		8,677	18 months
Accumulated ARO Accretion/Depreciation Adjustment¹		—		5,672		5,672	asset lives
Big Stone II Unrecovered Project Costs – Minnesota¹		942		2,620		3,562	84 months
Debt Reacquisition Premiums¹		351		1,539		1,890	201 months
Deferred Income Taxes¹		—		1,455		1,455	asset lives
North Dakota Renewable Resource Rider Accrued Revenues²		—		1,266		1,266	15 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up²		698		355		1,053	24 months
Big Stone II Unrecovered Project Costs – South Dakota²		100		643		743	89 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues²		576		—		576	12 months
Minnesota Deferred Rate Case Expenses Subject to Recovery¹		291		—		291	12 months
Minnesota Renewable Resource Rider Accrued Revenues²		—		68		68	see below
South Dakota Transmission Cost Recovery Rider Accrued Revenues²		33		—		33	12 months
Total Regulatory Assets	$	18,904	$	127,707	$	146,611
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	74,948	$	74,948	asset lives
Refundable Fuel Clause Adjustment Revenues		1,834		—		1,834	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		—		1,279		1,279	see below
Deferred Income Taxes		—		1,110		1,110	asset lives
Minnesota Environmental Cost Recovery Rider Accrued Refund		777		—		777	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		321		—		321	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		185		—		185	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		132		—		132	12 months
Deferred Gain on Sale of Utility Property – Minnesota Portion		5		95		100	216 months
North Dakota Renewable Resource Rider Accrued Refund		68		—		68	12 months
Total Regulatory Liabilities	$	3,322	$	77,432	$	80,754
Net Regulatory Asset Position	$	15,582	$	50,275	$	65,857

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 Losses recorded as of September 30, 2016 relate to forward purchases of energy scheduled for delivery through December 2020.

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

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

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

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2016.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 192 months.

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

Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.

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

The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of September 30, 2016.

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of September 30, 2016.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016.

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

The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of September 30, 2016.

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of September 30, 2016.

Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.

The Minnesota 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, 2016.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of September 30, 2016.

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of September 30, 2016.

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

5. Open Contract Positions Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows forward contract fair value positions subject to legally enforceable netting arrangements as of September 30, 2016 and December 31, 2015:

(in thousands)	September 30, 2016			December 31, 2015
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	—		$	—
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(15,220	)		(16,070	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(15,220	)	$	(16,070	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in loss positions as of September 30, 2016 and December 31, 2015:

Loss Position (in thousands)	September 30, 2016		December 31, 2015
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	49	$	199
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade¹		15,171		15,871
Loss Contracts with No Ratings Triggers or Deposit Requirements		—		—
Loss Position	$	15,220	$	16,070
¹ Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	15,171	$	15,871
Offsetting Gains with Counterparties under Master Netting Agreements		—		—
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	15,171	$	15,871

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, 2015	$	189,286		$	293,610		$	126,025		$	(3,898	)	$	605,023
Common Stock Issuances, Net of Expenses		6,855			34,601									41,456
Common Stock Retirements		(18	)		(86	)								(104	)
Net Income								44,811						44,811
Other Comprehensive Income											322			322
Employee Stock Incentive Plans Expense					1,163									1,163
Common Dividends ($0.9375 per share)								(35,952	)					(35,952	)
Balance, September 30, 2016	$	196,123		$	329,288		$	134,884		$	(3,576	)	$	656,719

Shelf Registration

The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018. 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.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2015 through September 30, 2016:

Common Shares Outstanding, December 31, 2015	37,857,186
Issuances:
At-the-Market Offering	977,712
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	131,111
Cash Invested	79,494
Executive Stock Performance Awards (2013 and 2014 shares earned)	54,700
Employee Stock Purchase Plan:
Cash Invested	40,324
Dividends Reinvested	19,090
Employee Stock Ownership Plan	23,837
Restricted Stock Issued to Directors	23,200
Vesting of Restricted Stock Units	21,025
Directors Deferred Compensation	542
Retirements:
Shares Withheld for Individual Income Tax Requirements	(3,668	)
Common Shares Outstanding, September 30, 2016	39,224,553

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, 2016 and 2015. 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:

	Three Months ended September 30				Nine Months ended September 30
	2016		2015		2016		2015
Weighted Average Common Shares Outstanding – Basic		38,832,659		37,575,413		38,316,324		37,417,283
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance		103,084		141,540		80,450		141,540
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		48,645		44,280		42,620		44,280
Nonvested Restricted Shares		18,029		31,079		14,556		31,079
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,289		2,231		3,451		2,231
Total Dilutive Shares		173,047		219,130		141,077		219,130
Weighted Average Common Shares Outstanding – Diluted		39,005,706		37,794,543		38,457,401		37,636,413

The effect of dilutive shares on earnings per share for the three- and nine-month periods ended September 30, 2016 and 2015, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

7. Share-Based Payments

Stock Incentive Awards

In 2016 the following stock incentive awards were granted to the Company’s employees and nonemployee directors under the 2014 Stock Incentive Plan:

Award	Shares/ Units Granted		Grant-Date Fair Value per Award		Vesting
February 4, 2016:
Stock Performance Awards Granted to Executive Officers		81,500	$	24.03	December 31, 2018
Restricted Stock Units Granted to Executive Officers		22,000	$	28.915	25% per year through February 6, 2020
April 11, 2016:
Restricted Stock Granted to Nonemployee Directors		23,200	$	28.66	25% per year through April 8, 2020
Restricted Stock Units Granted to Key Employees		15,800	$	24.00	100% on April 8, 2020
September 21, 2016:
Restricted Stock Units Granted to Key Employee		1,420	$	30.59	100% on April 8, 2020

Under the 2016 performance share award agreements, the aggregate award for performance at target is 81,500 shares. For target performance the Company’s executive officers would earn an aggregate of 54,333 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2016 through December 31, 2018, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2016 and the average closing price for the 20 trading days immediately preceding January 1, 2019, respectively. The Company’s executive officers would also earn an aggregate of 27,167 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. Actual payment may range from zero to 150% of the target amount, or up to an aggregate of 122,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement 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 2016 performance share 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 these performance share award agreements is accelerated and paid out at target in the event of a change in control, disability or death (and on retirement at or after the age of 62 for certain officers who are parties to executive employment agreements with the Company).

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

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

As of September 30, 2016 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.1 million (before income taxes) which will be amortized over a weighted-average period of 2.4 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, 2016 and 2015 are presented in the table below:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2016		2015			2016		2015
Stock Performance Awards Granted to Executive Officers	$	455	$	(142	)	$	1,296	$	915
Restricted Stock Units Granted to Executive Officers		64		36			373		416
Restricted Stock Granted to Executive Officers		22		29			73		330
Restricted Stock Granted to Directors		128		107			363		311
Restricted Stock Units Granted to Nonexecutive Employees		62		86			207		233
Employee Stock Purchase Plan (15% discount)		47		44			135		138
Totals	$	778	$	160		$	2,447	$	2,343

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, there are limitations on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP debt 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, 2016 the Company was in compliance with these financial covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2015 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 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. OTP’s equity to total capitalization ratio including short-term debt was 52.9% as of September 30, 2016. Total capitalization for OTP cannot currently exceed $1,123,168,000.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2015 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $89.6 million. At September 30, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $137.4 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 2040. In 2016, OTP entered into a $3.5 million electric generating capacity purchase agreement for the period June 2017 through May 2019.

OTP has commitments under contracts providing for the purchase and delivery of a significant portion of its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040, respectively. In January 2016, OTP entered into an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant for the period of January 1, 2016 through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement.

Operating Leases

OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. On September 27, 2016 OTP entered into an agreement to lease rail cars for the delivery of coal to Big Stone Plant through October of 2026 with OTP’s share of the lease payments totaling $970,000 over the term of the lease. The Company’s

nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.

Contingencies

Based on the reduction by the FERC in the ROE component of the MISO Tariff, OTP has a $2.4 million liability on its balance sheet as of September 30, 2016, representing OTP’s best estimate of its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery under state jurisdictional TCR riders.

OTP was a party to proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005. As many as 200 utilities, generators and power marketers participated in the proceedings, which concluded on May 2, 2016. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with FERC to market participants, revisions to the RSG rate based on several FERC orders and FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the United States Court of Appeals for the District of Columbia (D.C. Circuit). The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is both a petitioner and an intervenor in these cases. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

In 2014, the Environmental Protection Agency (EPA) published proposed standards of performance for 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 under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. All of these rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. On February 9, 2016 the U.S. Supreme Court granted a stay of the CO2 emission guidelines for existing fossil fuel-fired power plants, pending disposition of petitions for review in the D.C. Circuit and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. The D.C. Circuit heard oral argument on challenges to the CO2 emission guidelines on September 27, 2016 before the full court, and a decision may be rendered in late 2016 or early 2017. Given the pending litigation, uncertainty regarding the status of the rules will likely continue for some time. OTP is actively engaged with the stakeholder processes in each of its states that have continued to move forward with planning efforts during the stay.

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all other matters pending as of September 30, 2016 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, 2016 and December 31, 2015:

(in thousands)	Line Limit		In Use on September 30, 2016		Restricted due to Outstanding Letters of Credit		Available on September 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	—	$	—		$ 150 000	$	90,334
OTP Credit Agreement		170,000		37,173		50		132,777		148,694
Total	$	320,000	$	37,173	$	50	$	282,777	$	239,028

On October 31, 2016 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, 2020 to October 29, 2021. Also, the line limit on the Otter Tail Corporation Credit Agreement was reduced from $150 million to $130 million.

Debt Issuances and Retirements

2016 Note Purchase Agreement—On September 23, 2016 the Company entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which the Company has agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of the Company’s 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The Company’s obligations under the 2016 Note Purchase Agreement and the 2026 Notes will be guaranteed by the Company’s Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The 2026 Notes are expected to be issued on December 13, 2016, subject to the satisfaction of certain customary conditions to closing.

The Company may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries sell a “substantial part” of their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, the Company is required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. These include restrictions on the Company’s and the Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on the Company’s and the Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. Specifically, the Company may not permit the ratio of its Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) to Total Capitalization (as defined in the 2016 Note Purchase Agreement) to be greater than 0.60 to 1.00, determined as of the end of each fiscal quarter, and may not permit the Interest and Dividend Coverage Ratio (as defined in the 2016 Note Purchase Agreement) to be less than 1.50 to 1.00 for any period of four consecutive fiscal quarters. The Company is also restricted from allowing its Priority Debt (as defined in the 2016 Note Purchase Agreement) to exceed 10% of Total Capitalization, determined as of the end of each fiscal quarter. The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s or the Material Subsidiaries’ credit ratings.

The Company intends to use the proceeds of the 2026 Notes to repay existing debt, including the remaining $52,330,000 of its 9.000% Senior Notes due December 15, 2016, and for general corporate purposes.

$50 Million Term Loan Agreement—On February 5, 2016 the Company entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A., as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company’s election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018. The Term Loan Agreement contains a number of restrictions on the Company, Varistar and certain subsidiaries of Varistar, including restrictions on their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, and certain financial covenants. Specifically, the Company must not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis), as provided in the Term Loan Agreement. The Term Loan Agreement does not include provisions for the termination of the

agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s credit ratings. The Company’s obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.

On February 5, 2016 the Company borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2016 and December 31, 2015:

September 30, 2016 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	37,173	$	—	$	37,173
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330	$	52,330
Term Loan, LIBOR plus 0.90%, due February 5, 2018				50,000		50,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018				126		126
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				873		873
Total	$	445,000	$	103,329	$	548,329
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,958		52,532		85,490
Unamortized Long-Term Debt Issuance Costs		1,920		162		2,082
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,122	$	50,635	$	460,757
Total Short-Term and Long-Term Debt (with current maturities)	$	480,253	$	103,167	$	583,420

December 31, 2015 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	21,006	$	59,666	$	80,672
Long-Term Debt:
9.000% Notes, due December 15, 2016			$	52,330	$	52,330
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
Senior Unsecured Notes 4.63%, due December 1, 2021		140,000				140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022		30,000				30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027		42,000				42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029		60,000				60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037		50,000				50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044		90,000				90,000
North Dakota Development Note, 3.95%, due April 1, 2018				182		182
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				977		977
Total	$	445,000	$	53,489	$	498,489
Less: Current Maturities net of Unamortized Debt Issuance Costs				52,422		52,422
Unamortized Long-Term Debt Issuance Costs		2,099		122		2,221
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	442,901	$	945	$	443,846
Total Short-Term and Long-Term Debt (with current maturities)	$	463,907	$	113,033	$	576,940

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)	2016			2015			2016			2015
Service Cost—Benefit Earned During the Period	$	1,376		$	1,514		$	4,139		$	4,544
Interest Cost on Projected Benefit Obligation		3,603			3,336			10,646			10,008
Expected Return on Assets		(4,857	)		(4,595	)		(14,590	)		(13,787	)
Amortization of Prior-Service Cost:
From Regulatory Asset		48			47			142			141
From Other Comprehensive Income¹		1			2			3			4
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,411			1,669			3,865			5,007
From Other Comprehensive Income¹		32			42			95			128
Net Periodic Pension Cost	$	1,614		$	2,015		$	4,300		$	6,045
¹Corporate cost included in Other Nonelectric Expenses.

Cash flows—The Company made discretionary plan contributions totaling $10,000,000 in January 2016. The Company currently is not required and does not expect to make an additional contribution to the plan in 2016. The Company also made discretionary plan contributions totaling $10,000,000 in January 2015.

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)	2016		2015		2016		2015
Service Cost—Benefit Earned During the Period	$	63	$	48	$	189	$	142
Interest Cost on Projected Benefit Obligation		417		380		1,251		1,142
Amortization of Prior-Service Cost:
From Regulatory Asset		4		5		12		13
From Other Comprehensive Income¹		9		9		28		28
Amortization of Net Actuarial Loss:
From Regulatory Asset		74		83		220		250
From Other Comprehensive Income²		111		151		334		452
Net Periodic Pension Cost	$	678	$	676	$	2,034	$	2,027
¹Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	3	$	3	$	11	$	11
Other Nonelectric Expenses		6		6		17		17
²Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	68	$	78	$	204	$	233
Other Nonelectric Expenses		43		73		130		219

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)	2016			2015			2016			2015
Service Cost—Benefit Earned During the Period	$	365		$	324		$	976		$	972
Interest Cost on Projected Benefit Obligation		794			524			1,877			1,573
Amortization of Prior-Service Cost:
From Regulatory Asset		34			52			100			154
From Other Comprehensive Income¹		1			1			3			4
Amortization of Net Actuarial Loss:
From Regulatory Asset		284			—			284			—
From Other Comprehensive Income¹		7			—			7			—
Net Periodic Postretirement Benefit Cost	$	1,485		$	901		$	3,247		$	2,703
Effect of Medicare Part D Subsidy	$	(177	)	$	(372	)	$	(692	)	$	(1,115	)
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:

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2016 and December 31, 2015 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, 2016						December 31, 2015
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Short-Term Debt		(37,173	)		(37,173	)		(80,672	)		(80,672	)
Long-Term Debt including Current Maturities		(546,247	)		(618,875	)		(496,268	)		(561,245	)

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:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015
Income Before Income Taxes – Continuing Operations	$	19,757		$	22,230		$	60,378		$	57,749
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,705			8,670			23,547			22,522
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,423	)		(1,437	)		(4,994	)		(5,147	)
R&D Tax Credits		(223	)		2			(445	)		(7	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)		(637	)		(637	)
Employee Stock Ownership Plan Dividend Deduction		(157	)		(171	)		(472	)		(514	)
Corporate Owned Life Insurance		(92	)		185			(664	)		(39	)
Investment Tax Credits		(87	)		(143	)		(262	)		(428	)
Adjustment for Uncertain Tax Positions		(57	)		281			(31	)		367
AFUDC Equity		(51	)		(144	)		(238	)		(369	)
Section 199 Domestic Production Activities Deduction		(9	)		(362	)		(207	)		(1,087	)
Other Items – Net		(231	)		(148	)		141			(59	)
Income Tax Expense – Continuing Operations	$	5,163		$	6,521		$	15,738		$	14,602
Effective Income Tax Rate – Continuing Operations		26.1	%		29.3	%		26.1	%		25.3	%

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

(in thousands)	2016			2015
Balance on January 1	$	468		$	222
Increases Related to Tax Positions for Prior Years		40			236
Increases Related to Tax Positions for Current Year		26			131
Uncertain Positions Resolved During Year		(97	)		—
Balance on September 30	$	437		$	589

The balance of unrecognized tax benefits as of September 30, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2016 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of September 30, 2016.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal income taxes and Minnesota and North Dakota 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. On February 28, 2015 the Company sold the assets of AEV, Inc. its former energy and electrical construction contractor. On February 8, 2013 the Company completed the sale of substantially all the assets of its former dock and boatlift company and on November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing business. The Company’s Construction and Wind Energy segments were eliminated as a result of the sales of Foley, AEV, Inc. and its former wind tower manufacturing business. The financial position, results of operations and cash flows of Foley, AEV, Inc., the Company’s former dock and boatlift company and its former wind tower manufacturing business are reported as discontinued operations in the Company’s consolidated financial statements. Following are summary presentations of the results of discontinued operations:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2016			2015			2016			2015
Operating Revenues	$	—		$	—		$	—		$	24,623
Operating Expenses		(36	)		420			(285	)		31,770
Goodwill Impairment Charge		—			—			—			1,000
Operating Income (Loss)		36			(420	)		285			(8,147	)
Other Deductions		—			—			—			(42	)
Income Tax Expense (Benefit)		14			(168	)		114			(2,873	)
Net Income (Loss) from Operations		22			(252	)		171			(5,316	)
(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 Income (Loss)	$	22		$	(317	)	$	171		$	1,616

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, mainly related to the settlement of a warranty claim in the second quarter of 2015, from the Company’s former waterfront equipment manufacturer, 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. 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 $4.4 million in the nine-month period ended September 30, 2015.

Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2016 and December 31, 2015:

(in thousands)	September, 30 2016		December 31, 2015
Current Assets	$	249	$	—
Assets of Discontinued Operations	$	249	$	—
Current Liabilities	$	1,631	$	2,098
Liabilities of Discontinued Operations	$	1,631	$	2,098

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

(in thousands)	2016			2015
Warranty Reserve Balance, January 1	$	2,103		$	2,527
Additional Provision for Warranties Made During the Year		—			—
Settlements Made During the Year		(24	)		(115	)
Decrease in Warranty Estimates for Prior Years		(530	)		(100	)
Warranty Reserve Balance, September 30	$	1,549		$	2,312

The warranty reserve balances as of September 30, 2016 relate entirely to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried one to fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated net income and financial condition.

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, 2016 and 2015, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2016 and our business outlook for the remainder of 2016.

Comparison of the Three Months Ended September 30, 2016 and 2015

Consolidated operating revenues were $197.2 million for the three months ended September 30, 2016 compared with $200.0 million for the three months ended September 30, 2015. Operating income was $27.3 million for the three months ended September 30, 2016 compared with $29.6 million for the three months ended September 30, 2015. The Company recorded diluted earnings per share from continuing operations of $0.37 for the three months ended September 30, 2016 compared with $0.42 for the three months ended September 30, 2015, and total diluted earnings per share of $0.37 for the three months ended September 30, 2016 compared with $0.41 for the three months ended September 30, 2015.

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, 2016 and 2015 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, 2016		September 30, 2015
Operating Revenues:
Electric	$	11	$	29
Nonelectric		—		—
Cost of Products Sold		—		1
Other Nonelectric Expenses		11		28

Electric

	Three Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Retail Sales Revenues	$	87,755	$	89,140	$	(1,385	)		(1.6	)
Wholesale Revenues – Company Generation		1,656		377		1,279			339.3
Net Revenue – Energy Trading Activity		—		2		(2	)		(100.0	)
Other Revenues		13,312		11,048		2,264			20.5
Total Operating Revenues	$	102,723	$	100,567	$	2,156			2.1
Production Fuel		14,789		11,124		3,665			32.9
Purchased Power – System Use		11,473		18,725		(7,252	)		(38.7	)
Other Operation and Maintenance Expenses		36,207		32,648		3,559			10.9
Depreciation and Amortization		13,408		11,190		2,218			19.8
Property Taxes		3,506		3,560		(54	)		(1.5	)
Operating Income	$	23,340	$	23,320	$	20			0.1
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,095,236		1,082,062		13,174			1.2
Wholesale kwh Sales – Company Generation		61,244		22,116		39,128			176.9
Wholesale kwh Sales – Purchased Power Resold		—		10		(10	)		(100.0	)
Heating Degree Days		23		20		3			15.0
Cooling Degree Days		317		396		(79	)		(19.9	)

The following table shows cooling degree days as a percent of normal:

	Three Months ended September 30,
	2016			2015
Cooling Degree Days		89.5	%		111.5	%

The following table summarizes the estimated impact of weather changes on diluted earnings per share compared with sales under normal weather conditions and the third quarter of 2015:

	Three Months ended September 30,
	2016 vs Normal			2015 vs Normal		2016 vs 2015
Impact on Diluted Earnings Per Share	$	(0.01	)	$	0.0	$	(0.01	)

The $1.4 million decrease in retail revenue includes:

	·	A $3.8 million increase in retail revenue related to a 9.56% interim rate increase implemented in April 2016 in conjunction with Otter Tail Power Company’s (OTP's) 2016 general rate increase request in Minnesota.

	·	A $1.2 million increase in Environmental Cost Recovery (ECR) rider revenue due to the recovery of additional investment and costs related to the operation of the air quality control system (AQCS) at Big Stone Plant that was placed in service in December 2015.

	·	A $0.8 million increase in revenue related to increased kwh sales across all customer classes, offsetting the negative impact of milder weather on kwh sales and revenue.

	·	A $0.8 million increase in Conservation Improvement Program (CIP) cost recovery and incentive revenues.

	·	A $0.2 million increase in Transmission Cost Recovery (TCR) and Renewable Resource Adjustment (RRA) rider revenues related to increased investment in transmission plant and renewable energy resources.

more than offset by:

	·	A $5.3 million decrease in fuel and purchased power cost recovery revenues mainly due to a 48.3% decrease in kwhs purchased partially offset by a 28.3% increase in generation at a lower fuel-cost-per-kwh than the cost of purchased power.

A $2.1 million reduction in interim rate revenues recorded to provide for an estimated refund related to a modification in OTP’s original request and other expected outcomes in the pending Minnesota general rate case.

A $0.8 million decrease in revenues from reduced demand due to milder weather in the third quarter of 2016, evidenced by a 19.9% decrease in cooling degree days compared to the third quarter of 2015.

Revenue from wholesale electric sales from company-owned generation increased $1.3 million while fuel costs for wholesale generation increased $0.8 million, resulting in a $0.5 million increase in wholesale revenue net of fuel costs.

Other electric revenues increased $2.3 million as a result of:

	·	A $2.7 million increase in Midcontinent Independent System Operator, Inc. (MISO) transmission tariff revenues related to increased investment in regional transmission lines and driven in part by returns on and recovery of Capacity Expansion 2020 (CapX2020) and MISO-designated multi-value project (MVP) investment costs and operating expenses.

	·	A $0.6 million increase in MISO network integration transmission service revenues as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and becoming a member the Southwest Power Pool (SPP) in 2016.

	·	A $0.2 million increase in steam sales from Big Stone Plant to a nearby ethanol plant as a result of Big Stone Plant being fully operational in the third quarter of 2016 compared to operating in only August and September of 2015.

offset by:

	·	A $0.9 million decrease in revenue related to a reduction in work performed on projects for another regional transmission owner.

A $0.4 million reduction in integrated transmission agreement revenues from two regional transmission providers related to the curtailment of services under an agreement with one provider and termination of an agreement with the other provider.

Production fuel costs increased $3.7 million as a result of a 40.5% increase in kwhs generated from our steam-powered and combustion turbine generators, related to Big Stone Plant and Coyote Station being fully operational in the third quarter of 2016. In the third quarter of 2015, Big Stone Plant was down for an extended maintenance outage and Coyote Station was operating at reduced load due to ongoing repairs related to a December 2014 boiler feed pump failure and fire.

The cost of purchased power to serve retail customers decreased $7.3 million due to a 48.3% decrease in kwhs purchased partially offset by an 18.6% increase in the cost per kwh purchased. The decrease in kwhs purchased was the result of increased availability and generation from company-owned resources. The increased cost per kwh purchased is related to contractual prices being paid for purchased power under a long-term supply agreement.

Electric operating and maintenance expenses increased $3.6 million as a result of:

	·	A $1.2 million increase in MISO transmission service charges due to increased transmission investment by other MISO members.

	·	A $0.9 million increase in operating supply and maintenance costs mainly related to increased generation at Coyote Station and Big Stone Plant and increased expenditures for vegetation maintenance.

	·	A $0.6 million increase in storm repair and other expenses mainly associated with excessive storm damage in OTP’s Minnesota service area in July of 2016.

	·	A $0.6 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with Environmental Protection Agency (EPA) power plant emission regulations.

	·	A $0.5 million increase in transmission expenses from the SPP as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and becoming a member of the SPP in 2016.

	·	A $0.2 million increase in CIP program expenditures.

offset by:

A $0.5 million decrease in costs related to a reduction in work performed on projects for another regional transmission owner.

Depreciation and amortization expense increased $2.2 million mainly due to the Big Stone Plant AQCS being placed in service in December 2015.

Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Operating Revenues	$	52,171	$	52,460	$	(289	)		(0.6	)
Cost of Products Sold		40,616		40,961		(345	)		(0.8	)
Operating Expenses		5,246		5,094		152			3.0
Depreciation and Amortization		3,927		2,936		991			33.8
Operating Income	$	2,382	$	3,469	$	(1,087	)		(31.3	)

The $0.3 million decrease in revenues in our Manufacturing segment includes the following:

Revenues at BTD Manufacturing, Inc. (BTD) increased $1.6 million, including:

A $3.7 million increase in revenues at BTD-Georgia as a result of BTD acquiring and operating the Georgia plant in September 2015, compared with three months of operations in the third quarter of 2016.

offset by:

A $2.1 million decrease in revenues at BTD’s Minnesota and Illinois plants, mainly related to a decline in sales to manufacturers of recreational and agricultural equipment and heavy machinery due to softness in end markets served by those manufacturers.

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $1.9 million, including a $1.2 million decrease in industrial market sales and a $0.6 million decrease in revenues from sales of horticultural containers. The decrease in industrial market sales is primarily due to a continued decline in sales volumes to a customer insourcing product into its own manufacturing facilities.

The $0.3 million decrease in cost of products sold in our Manufacturing segment includes the following:

Cost of products sold at BTD increased $0.3 million. This includes a $4.0 million increase in cost of products sold at BTD-Georgia, offset by a $3.7 million decrease in cost of products sold at BTD’s other facilities. The $3.7 million decrease is related to the decrease in sales.

Cost of products sold at T.O. Plastics decreased $0.6 million as a result of the reduction in sales.

Operating expenses at BTD increased $0.5 million, mainly in the areas of labor and benefit costs and computer-related expenditures, and included a $0.2 million increase in operating expenses at BTD-Georgia.

Operating expenses at T.O. Plastics decreased $0.4 million as a result of decreases in selling, benefits and administrative and general expenses.

The $1.0 million increase in depreciation and amortization expenses in our Manufacturing segment includes a $0.6 million increase at BTD-Georgia and a $0.5 million increase at BTD’s Minnesota facilities as a result of placing new assets in service in Minnesota in 2015 and 2016, offset by a $0.1 million decrease at T.O. Plastics.

Plastics

	Three Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Operating Revenues	$	42,292	$	47,025	$	(4,733	)		(10.1	)
Cost of Products Sold		34,789		37,468		(2,679	)		(7.2	)
Operating Expenses		2,346		2,655		(309	)		(11.6	)
Depreciation and Amortization		970		914		56			6.1
Operating Income	$	4,187	$	5,988	$	(1,801	)		(30.1	)

The $4.7 million decrease in Plastics segment revenues is the result of a 10.4% decrease in the price per pound of polyvinyl chloride (PVC) pipe sold, while quarter over quarter sales volume was essentially unchanged. The decline in sales price per pound is due to a continued softening in sales prices as a result of lower raw material prices. Increased pipe sales in Colorado and Utah and the Midwest and South-Central regions of the United States were mostly offset by decreased sales volumes in

California, Minnesota and North Dakota. Lower material costs, which did not decline as much as sales prices, resulted in a $2.7 million decrease in costs of product sold. The cost decrease in combination with a $0.3 million decrease in operating expenses did not offset the impact of lower pipe prices, resulting in a $1.8 million decrease in Plastics segment operating income.

The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower.

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)	2016		2015		Change			Change
Operating Expenses	$	2,616	$	3,050		(434	)		(14.2	)
Depreciation and Amortization		9		101		(92	)		(91.1	)

Corporate operating expenses decreased $0.4 million between the quarters mainly related to decreases in insurance costs related to reduced claims at our captive insurance company and reductions in accounting and legal fees, partially offset by an increase in employee benefit costs.

Interest Charges

The $0.3 million increase in interest charges in the three months ended September 30, 2016 compared with the three months ended September 30, 2015 is related to an increase in the average level of the Company’s consolidated variable rate short-term and long-term debt outstanding between the quarters.

Income Taxes – Continuing Operations

Income tax expense - continuing operations decreased $1.4 million in the three months ended September 30, 2016 compared with the three months ended September 30, 2015, mostly as a result of a $2.5 million reduction in income from continuing operations before income taxes. 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:

(in thousands)	2016			2015
Income Before Income Taxes – Continuing Operations	$	19,757		$	22,230
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		7,705			8,670
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,423	)		(1,437	)
R&D Tax Credits		(223	)		2
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(157	)		(171	)
Corporate Owned Life Insurance		(92	)		185
Investment Tax Credits		(87	)		(143	)
Adjustment for Uncertain Tax Positions		(57	)		281
AFUDC Equity		(51	)		(144	)
Section 199 Domestic Production Activities Deduction		(9	)		(362	)
Other Items – Net		(231	)		(148	)
Income Tax Expense – Continuing Operations	$	5,163		$	6,521
Effective Income Tax Rate – Continuing Operations		26.1	%		29.3	%

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 was essentially the same in the three months ended September 30, 2016 compared with the three months ended September 30, 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Discontinued Operations

On April 30, 2015 we sold Foley Company (Foley), our former water, wastewater, power and industrial construction contractor. On February 28, 2015 we sold the assets of AEV, Inc. our former energy and electrical construction contractor. On February 8, 2013 we completed the sale of substantially all the assets of our former dock and boatlift company and on November 30, 2012 we completed the sale of the assets of our former wind tower manufacturing business. Our Construction and Wind Energy segments were eliminated as a result of the sales of Foley, AEV, Inc. and our former wind tower manufacturing business. The financial position, results of operations and cash flows of Foley, AEV, Inc., our former dock and boatlift company and our former wind tower manufacturing business are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the three-month periods ended September 30:

(in thousands)	2016			2015
Operating Revenues	$	—		$	—
Operating Expenses		(36	)		420
Operating Income (Loss)		36			(420	)
Income Tax Expense (Benefit)		14			(168	)
Net Income (Loss) from Operations		22			(252	)
Loss on Disposition Before Taxes		—			(108	)
Income Tax Benefit on Disposition		—			(43	)
Net Loss on Disposition		—			(65	)
Net Income (Loss)	$	22		$	(317	)

Comparison of the Nine Months Ended September 30, 2016 and 2015

Consolidated operating revenues were $606.9 million for the nine months ended September 30, 2016 compared with $591.0 million for the nine months ended September 30, 2015. Operating income was $81.9 million for the nine months ended September 30, 2016 compared with $79.5 million for the nine months ended September 30, 2015. The Company recorded diluted earnings per share from continuing operations of $1.16 for the nine months ended September 30, 2016 compared to $1.15 for the nine months ended September 30, 2015 and total diluted earnings per share of $1.17 for the nine months ended September 30, 2016 compared to $1.19 for the nine months ended September 30, 2015.

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, 2016 and 2015 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, 2016		September 30, 2015
Operating Revenues:
Electric	$	27	$	80
Nonelectric		—		4
Cost of Products Sold		—		5
Other Nonelectric Expenses		27		79

Electric

	Nine Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Retail Sales Revenues	$	274,395	$	272,258	$	2,137			0.8
Wholesale Revenues – Company Generation		3,426		1,651		1,775			107.5
Net Revenue – Energy Trading Activity		—		187		(187	)		(100.0	)
Other Revenues		35,821		30,982		4,839			15.6
Total Operating Revenues	$	313,642	$	305,078	$	8,564			2.8
Production Fuel		40,479		29,906		10,573			35.4
Purchased Power – System Use		43,486		62,101		(18,615	)		(30.0	)
Other Operation and Maintenance Expenses		115,206		107,929		7,277			6.7
Depreciation and Amortization		40,323		33,391		6,932			20.8
Property Taxes		10,774		10,324		450			4.4
Operating Income	$	63,374	$	61,427	$	1,947			3.2
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		3,517,153		3,437,261		79,892			2.3
Wholesale kwh Sales – Company Generation		141,817		66,592		75,225			113.0
Wholesale kwh Sales – Purchased Power Resold		—		5,547		(5,547	)		(100.0	)
Heating Degree Days		3,277		3,779		(502	)		(13.3	)
Cooling Degree Days		450		479		(29	)		(6.1	)

The following table shows heating and cooling degree days as a percent of normal:

	Nine Months ended September 30,
	2016			2015
Heating Degree Days		82.1	%		93.7	%
Cooling Degree Days		97.6	%		103.0	%

The following table summarizes the estimated impact of weather changes on diluted earnings per share compared with sales under normal weather conditions and to the first nine months of 2015:

	Nine Months ended September 30,
	2016 vs Normal			2015 vs Normal			2016 vs 2015
Effect on Diluted Earnings Per Share	$	(0.05	)	$	(0.01	)	$	(0.04	)

The $2.1 million increase in retail revenue includes:

A $6.9 million increase in retail revenue related to a 9.56% interim rate increase implemented in April 2016 in conjunction with OTP's 2016 general rate increase request in Minnesota.

A $3.2 million increase in ECR rider revenue due to the recovery of additional investment and costs related to the operation of the AQCS at Big Stone Plant that was placed in service in December 2015.

A $2.7 million increase in revenue related to an increase in retail kwh sales, mainly to pipeline customers.

A $2.0 million increase in CIP cost recovery and incentive revenues.

A $1.9 million increase in TCR rider revenues related to increased investment in transmission plant.

A $0.3 million increase in RRA rider revenues.

offset by:

A $10.2 million decrease in fuel and purchased power cost recovery revenues mainly due to an 18.8% decrease in kwhs, purchased partially offset by a 22.2% increase in generation at a lower fuel-cost-per-kwh than the cost of purchased power.

A $2.4 million decrease in revenues related to decreased consumption due to milder weather in the first nine months of 2016, evidenced by a 13.3% reduction in heating-degree days and 6.1% reduction in cooling-degree days compared to the first nine months of 2015.

A $2.3 million reduction in interim rate revenues recorded to provide for an estimated refund related to a modification in OTP’s original request and other expected outcomes in the pending Minnesota general rate case.

Revenue from wholesale electric sales from company-owned generation increased $1.8 million while fuel costs for wholesale generation increased $1.4 million, resulting in a $0.4 million increase in wholesale revenue net of fuel costs as increased plant availability in 2016 has provided greater opportunity for OTP to respond to market demand.

Other electric revenues increased $4.8 million as a result of:

A $4.9 million increase in MISO transmission tariff revenues related to increased investment in regional transmission lines and driven in part by returns on and recovery of CapX2020 and MISO designated MVP investment costs and operating expenses.

A $0.7 million increase in steam sales to an ethanol plant near Big Stone Plant as a result of Big Stone Plant being fully operational in the first nine months of 2016 compared to being down for maintenance from March through July of 2015.

offset by:

A $0.8 million decrease in revenue related to a reduction in work performed on projects for another regional transmission owner.

Production fuel costs increased $10.6 million as a result of a 33.2% increase in kwhs generated from our steam-powered and combustion turbine generators, mainly related to Big Stone Plant being fully operational in the first nine months of 2016. In 2015 Big Stone Plant was off line for maintenance from March through July.

The cost of purchased power to serve retail customers decreased $18.6 million due to an 18.8% decrease in kwhs purchased in combination with a 13.8% decrease in the cost per kwh purchased. Greater availability of company-owned generation in 2016 reduced the need to purchase electricity to serve retail load. The decreased cost per kwh purchased was driven by lower market demand mainly resulting from milder weather and lower wholesale energy prices in the first nine months of 2016 compared with the first nine months of 2015.

Electric operating and maintenance expenses increased $7.3 million as a result of:

$3.1 million in transmission expenses from the SPP beginning in 2016 as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the SPP.

A $1.5 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with EPA power plant emission regulations.

A $1.3 million increase in MISO transmission service charges due to increased transmission investment by other MISO members.

A $1.3 million increase in CIP program expenditures.

A $0.7 million increase in storm repair expenses mainly associated with excessive storm damage in OTP's Minnesota service area in July of 2016.

A $0.6 million increase in operating supply expenses at Big Stone Plant and Coyote Station as generation at the plants increased in 2016.

$0.5 million in expenditures incurred in 2016 to resolve customer rate issues.

offset by:

A $1.0 million decrease in labor benefit costs related to a decrease in Corporate stock-based incentive expenses allocated to OTP.

A $0.4 million decrease in costs related to a reduction in work performed on projects for another regional transmission owner.

A $0.3 million reduction in other benefit related expenses.

Depreciation and amortization expense increased $6.9 million mainly due to the AQCS at Big Stone Plant being placed in service in December 2015 along with increased investment in transmission plant with the final phases of the Fargo-Monticello and Brookings-Southeast Twin Cities 345-kV transmission lines placed in service near the end of the first quarter of 2015.

The $0.5 million increase in property tax expense is related to property additions in Minnesota and North Dakota in 2015.

Manufacturing

	Nine Months Ended
	September 30,						%
(in thousands)	2016		2015		Change		Change
Operating Revenues	$	170,443	$	160,492	$	9,951		6.2
Cost of Products Sold		129,929		126,185		3,744		3.0
Operating Expenses		16,581		16,256		325		2.0
Depreciation and Amortization		11,891		8,161		3,730		45.7
Operating Income	$	12,042	$	9,890	$	2,152		21.8

The $10.0 million increase in revenues in our Manufacturing segment includes the following:

Revenues at BTD increased $13.3 million, including:

An $18.0 million increase in revenues at BTD-Georgia as a result of BTD acquiring and operating the Georgia plant in September of 2015 compared to nine months of operations in 2016.

A $5.5 million increase in revenues mainly related to the production of wind tower components at BTD’s Illinois plant.

offset by:

A $10.0 million decrease in revenues related to lower sales to manufacturers of recreational and agricultural equipment due to softness in end markets served by those manufacturers.

A $0.2 million decrease in revenues from sales of scrap metal due to a reduction in scrap metal prices.

Revenues at T.O. Plastics decreased $3.3 million due to a reduction in industrial market sales primarily as a result of a continued decline in sales volumes to a customer insourcing product into its own manufacturing facilities.

The $3.7 million increase in cost of products sold in our Manufacturing segment includes the following:

Cost of products sold at BTD increased $4.8 million. This includes a $16.2 million increase in cost of products sold at BTD-Georgia, offset by an $11.4 million net decrease in cost of products sold at BTD’s other facilities. The $11.4 million decrease is related to the decrease in sales, partially offset by an increase in costs of products sold at BTD’s Illinois plant as a result of the increase in the production of wind tower components.

Cost of products sold at T.O. Plastics decreased $1.1 million related to the decrease in sales.

Gross margins at BTD were positively impacted in the first nine months of 2016 by changes in customer product mix between periods.

The $0.3 million increase in operating expenses in our Manufacturing segment includes the following:

Operating expenses at BTD increased $1.2 million due to nine months of operations at BTD-Georgia in 2016 compared to one month in 2015.

Operating expenses at T.O. Plastics decreased $0.9 million, primarily as a result of a $0.4 million decrease in selling expenses and a $0.4 decrease in incentive benefits.

The $3.7 million increase in depreciation and amortization expenses in our Manufacturing segment includes a $2.3 million increase at BTD-Georgia and a $1.5 million increase at BTD’s other plants mainly as a result of placing new assets in service in Minnesota in 2015 and 2016.

Plastics

	Nine Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Operating Revenues	$	122,841	$	125,531	$	(2,690	)		(2.1	)
Cost of Products Sold		99,064		98,732		332			0.3
Operating Expenses		6,958		7,350		(392	)		(5.3	)
Depreciation and Amortization		2,880		2,625		255			9.7
Operating Income	$	13,939	$	16,824	$	(2,885	)		(17.1	)

The $2.7 million decrease in Plastics segment revenues is the result of a 12.5% decrease in the price per pound of pipe sold, partially offset by an 11.8% increase in pounds of pipe sold. The decline in sales price per pound is due to softening sales prices as a result of lower raw material prices between the periods. Increased pipe sales in the Midwest, South-Central and Western regions of the United States were mostly offset by decreased sales volumes in Minnesota, North Dakota and South Dakota. Cost of products sold increased $0.3 million due to the increase in sales volume, partly offset by a 10.3% decrease in the cost per pound of PVC pipe sold, as lower raw material prices did not decline as much as sales prices. Lower margins have resulted in reduced incentive benefits, which is the main factor contributing to the $0.4 million decrease in Plastics segment operating expenses.

Corporate

	Nine Months Ended
	September 30,							%
(in thousands)	2016		2015		Change			Change
Operating Expenses	$	7,378	$	8,530	$	(1,152	)		(13.5	)
Depreciation and Amortization		34		160		(126	)		(78.8	)

Corporate operating expenses decreased $1.2 million as a result of a $0.7 million decrease in expenditures for contracted services and a $0.5 million decrease in general insurance costs due to a decrease in claims at our captive insurance company.

Interest Charges

The $0.8 million increase in interest charges in the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015 is related to a $35 million increase in the average level of the Company’s consolidated variable rate short-term and long-term debt outstanding between the periods and a $0.2 million reduction in capitalized interest costs at OTP mainly related to the Big Stone Plant AQCS being placed in service in December 2015.

Other Income

The $1.0 million increase in other income includes $0.7 million in benefit proceeds received from corporate-owned life insurance in the second quarter of 2016 and a $0.4 million increase in life insurance policy cash surrender value increases in the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015.

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $1.1 million in the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015 as a result of a $2.6 million increase in income from continuing operations before income taxes. 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:

(in thousands)	2016			2015
Income Before Income Taxes – Continuing Operations	$	60,378		$	57,749
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		23,547			22,522
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(4,994	)		(5,147	)
Corporate Owned Life Insurance		(664	)		(39	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(637	)		(637	)
Employee Stock Ownership Plan Dividend Deduction		(472	)		(514	)
R&D Tax Credits		(445	)		(7	)
Investment Tax Credits		(262	)		(428	)
AFUDC Equity		(238	)		(369	)
Section 199 Domestic Production Activities Deduction		(207	)		(1,087	)
Adjustment for Uncertain Tax Positions		(31	)		367
Other Items – Net		141			(59	)
Income Tax Expense – Continuing Operations	$	15,738		$	14,602
Effective Income Tax Rate – Continuing Operations		26.1	%		25.3	%

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 2.3% in the nine months ended September 30, 2016 compared with the nine months ended September 30, 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Discontinued Operations

On April 30, 2015 we sold Foley, our former water, wastewater, power and industrial construction contractor. On February 28, 2015 we sold the assets of AEV, Inc. our former energy and electrical construction contractor, resulting in a first quarter 2015 net gain on the sale of $7.2 million. On February 8, 2013 we completed the sale of substantially all the assets of our former dock and boatlift company and on November 30, 2012 we completed the sale of the assets of our former wind tower manufacturing business. Our Construction and Wind Energy segments were eliminated as a result of the sales of Foley, AEV, Inc. and our former wind tower manufacturing business. The financial position, results of operations and cash flows of Foley, AEV, Inc., our former dock and boatlift company and our former wind tower manufacturing business are reported as discontinued operations in our consolidated financial statements. Following are summary presentations of the results of discontinued operations for the nine-month periods ended September 30:

(in thousands)	2016			2015
Operating Revenues	$	—		$	24,623
Operating Expenses		(285	)		31,770
Goodwill Impairment Charge		—			1,000
Operating Income (Loss)		285			(8,147	)
Other Deductions		—			(42	)
Income Tax Expense (Benefit)		114			(2,873	)
Net Income (Loss) from Operations		171			(5,316	)
Gain on Disposition Before Taxes		—			11,425
Income Tax Expense on Disposition		—			4,493
Net Gain on Disposition		—			6,932
Net Income	$	171		$	1,616

The above results for the nine months ended September 30, 2016 include net income of $0.3 million from the Company’s former wind tower manufacturer related to reductions in warranty reserves for expired warranties and a net loss of $0.2 million to settle indemnification issues related to the former operations of Foley. 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. 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 percentage of completion was based on the ratio of costs incurred to total estimated costs on construction projects in progress. In the first nine months of 2015, an increase in estimated costs in excess of previous period cost estimates on one large job in progress at Foley resulted in pretax charges of $4.4 million. Foley also recorded a $1.0 million goodwill impairment charge based on adjustments to its carrying value in the first quarter of 2015.

Financial Position

The following table presents the status of our lines of credit as of September 30, 2016 and December 31, 2015:

(in thousands)	Line Limit		In Use on September 30, 2016		Restricted due to Outstanding Letters of Credit		Available on September 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	—	$	—		$ 150 000	$	90,334
OTP Credit Agreement		170,000		37,173		50		132,777		148,694
Total	$	320,000	$	37,173	$	50	$	282,777	$	239,028

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. 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 11, 2018. On May 11, 2015, we entered into a Distribution Agreement with J.P. Morgan Securities LLC (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 through an At-the-Market offering program. We sold 467,573 shares under this program in the third quarter of 2016 and paid commissions to JPMS of $202,000.

Equity or debt financing will be required in the period 2016 through 2020 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 flows 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 the Company’s consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On January 28, 2016 our board of directors increased the quarterly dividend from $0.3075 to $0.3125 per common share.

Cash provided by operating activities of continuing operations was $115.1 million for the nine months ended September 30, 2016 compared with $81.8 million for the nine months ended September 30, 2015. The $33.3 million increase in cash provided by continuing operations between the periods includes:

A $10.8 million increase in non-cash depreciation expense.

A $10.7 million decrease in cash used for accounts payable at OTP, reflecting higher levels of payables in September 2016 for coal deliveries and transmission services and the payment, in January 2015, of large billings for coal transportation, coal and power purchased in December 2014.

A $10.5 million increase in cash from reduced levels of receivables between the periods, including $5.6 million at BTD, $2.5 million at Vinyltech and $1.0 million at T.O. Plastics.

A $4.0 million refund of 2015 estimated tax payments received in the first quarter of 2016, as a five-year extension of bonus depreciation for income taxes, approved on December 18, 2015, resulted in the elimination of any federal income tax liability for the Company in 2015.

In continuing operations, net cash used in investing activities was $123.4 million for the nine months ended September 30, 2016 compared with $150.5 million for the nine months ended September 30, 2015. The $27.1 million decrease in cash used for investing activities includes:

A $32.3 million decrease in cash used in acquisitions as we paid $30.8 million to acquire the assets of BTD-Georgia in September 2015 and received a purchase price adjustment of $1.5 million in June 2016.

A $4.1 million decrease in cash used for investments, reflecting the deposit of $2.5 million in proceeds from the sale of the assets of AEV, Inc. and Foley into escrow accounts and investments made by the Company’s captive insurance company in the first nine months of 2015, with no similar transactions in the first nine months of 2016.

A $1.2 million increase in cash from the disposal of noncurrent assets mainly related to the release of $2.0 million in remaining funds held in escrow accounts in the third quarter of 2016 related to the sales of AEV, Inc. and Foley, offset by a $0.8 million decrease in investments sold at our captive insurance company between the periods.

A $7.4 million decrease in capital expenditures in our Manufacturing segment as work on BTD’s Minnesota expansion project was winding down and nearing completion in the first half of 2016 compared to a high level of expenditures in the first nine months of 2015.

A $0.9 million decrease in capital expenditures in our PVC pipe companies.

offset by:

An $18.9 million increase in capital expenditures at OTP as work on the Big Stone South-Brookings and Big Stone South-Ellendale 345 kV transmission line projects ramped up in the first nine months of 2016 while work on the Big Stone Plant AQCS was winding down in the first nine months of 2015.

Investing activities of discontinued operations in the nine months ended September 30, 2015 include $21.3 million in cash proceeds from the sale of the assets of AEV, Inc., and $11.4 million from the sale of Foley stock, 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 $8.7 million for the nine months ended September 30, 2016 compared with $49.5 million for the nine months ended September 30, 2015. Financing activities in the first nine months of 2016 included $50 million in borrowings under a Term Loan Agreement and $39.4 million in net proceeds from the issuance of stock under the Company’s At-the-Market offering program and its automatic dividend reinvestment and share purchase plan, offset by $44.3 million in cash used to pay down short-term borrowings and checks written in excess of cash and $36.0 million in common stock dividend payments. The outstanding short-term borrowings that were paid down were, in part, used to fund the expansion of BTD’s Minnesota facilities in 2015 and the September 1, 2015 acquisition of BTD-Georgia. See note 6 to the Company’s consolidated financial statements for further information on stock issuances and retirements in the first nine months of 2016.

Net cash provided by financing activities in the first nine months of 2015 included $76.1 million in short-term borrowings used, in part, to fund capital expenditures, and $11.0 million in net proceeds from the issuance of common stock under our various stock purchase and dividend reinvestment plans, offset by $34.6 million in common stock dividend payments, $1.6 million in common stock retirement payments and $1.2 million used to reduce the balance of checks written in excess of cash.

CAPITAL REQUIREMENTS

2016-2020 Capital Expenditures

The following table shows our 2015 capital expenditures and 2016 through 2020 capital expenditures and electric utility average rate base anticipated at year-end 2015:

(in millions)	2015		2016		2017		2018		2019		2020
Capital Expenditures:
Electric Segment:
Transmission			$	107	$	96	$	51	$	5	$	7
Renewables and Natural Gas Generation				4		3		162		113		81
Other				46		41		40		51		51
Total Electric Segment	$	136	$	157	$	140	$	253	$	169	$	139
Manufacturing and Plastics Segments		24		18		38		19		20		19
Total Capital Expenditures	$	160	$	175	$	178	$	272	$	189	$	158
Total Electric Utility Average Rate Base			$	1,032	$	1,087	$	1,241	$	1,295	$	1,354

The capital expenditure plan for the 2016-2020 time period called for $858 million based on the need for additional wind and solar in rate base and capital spending on a natural gas-fired plant that is expected to replace Hoot Lake Plant when it is retired in 2021. Taking into account the increased capital expenditure plan along with the impact of bonus depreciation for income taxes, our compounded annual growth rate in rate base is expected to be 8.0% through 2020, using 2014 as a base year.

Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2016 through 2020 timeframe.

Contractual Obligations

Our contractual obligations reported in the table on page 50 of our Annual Report on Form 10-K for the year ended December 31, 2015 increased $92.7 million in the first nine months of 2016. Our other purchase obligations increased $85.5 million in 2017 and 2018 and $2.7 million in 2019, mainly as a result of additional purchase obligations entered into in the first nine months of 2016 related to the construction of the Big Stone South-Ellendale and Big Stone South-Brookings 345 kV transmission line MVPs. Our capacity and energy requirements obligations increased $2.7 million in 2017 and 2018 and $0.8 million in 2019 as a result of entering into a capacity purchase agreement for the period of June 2017 through May 2019 in May of 2016. Our operating lease obligations increased $0.2 million in 2017 and 2018, $0.2 million in 2019 and 2020, and $0.6 million in the years beyond 2020 as a result of OTP entering into an agreement to lease rail cars for the delivery of coal to Big Stone Plant through October of 2026.

CAPITAL RESOURCES

On May 11, 2015 we filed a shelf registration statement with the 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 11, 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 through an At-the-Market offering program. We sold 467,573 shares under this program in the third quarter of 2016 and paid commissions to JPMS of $202,000.

Short-Term Debt

The following table presents the status of our lines of credit as of September 30, 2016 and December 31, 2015:

(in thousands)	Line Limit		In Use on September 30, 2016		Restricted due to Outstanding Letters of Credit		Available on September 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	—	$	—		$ 150 000	$	90,334
OTP Credit Agreement		170,000		37,173		50		132,777		148,694
Total	$	320,000	$	37,173	$	50	$	282,777	$	239,028

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 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of certain 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 our wholly owned subsidiary, Varistar Corporation (Varistar) 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 31, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

Long-Term Debt

2016 Note Purchase Agreement—On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we have agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes will be guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The 2026 Notes are expected to be issued on December 13, 2016, subject to the satisfaction of certain customary conditions to closing.

We may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by us of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. We are required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if we and our Material Subsidiaries sell a “substantial part” of our or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s or the Material Subsidiaries’ credit ratings.

We intend to use the proceeds of the 2026 Notes to repay existing debt, including the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and for general corporate purposes.

Term Loan Agreement—On February 5, 2016 we entered into a Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A. (JPMorgan), as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that we may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, we may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on our election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.

On February 5, 2016 we borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia.

The Term Loan Agreement contains a number of restrictions on us, Varistar and certain subsidiaries of Varistar, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with related parties. The Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The Term Loan Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.

2013 Note Purchase Agreement—On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) 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 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, 2016.

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

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

Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, 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 of September 30, 2016 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement was 3.65 to 1.00.

Under the 2016 Note Purchase Agreement, we may not permit our Priority Indebtedness to exceed 10% of our Total Capitalization

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, 2016 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 3.64 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, 2016 our ratio of interest-bearing debt to total capitalization was 0.47 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $4.8 million, but our line of credit borrowing limits are only restricted by $50,000 in 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.

2016 BUSINESS OUTLOOK

We are reaffirming our consolidated diluted earnings per share guidance for 2016 to be in the range of $1.50 to $1.65. This guidance reflects the current mix of businesses we own, considers the cyclical nature of some of our businesses, and reflects current regulatory factors and economic challenges facing our Electric, Manufacturing and Plastics segments and strategies for improving future operating results. We expect capital expenditures for 2016 to be $159 million compared with $160 million in capital expenditures in 2015. Major projects in our planned expenditures for 2016 include investments in two large transmission line projects for the Electric segment, which positively impact earnings by providing an immediate return on invested funds through rider recovery mechanisms.

Segment components of our 2016 earnings per share initial and revised guidance range compared with 2015 actual earnings are as follows:

	2015 EPS by Segment			2016 Guidance February 8, 2016						2016 Guidance August 8, 2016						2016 Guidance November 2, 2016
Diluted Earnings Per Share				Low			High			Low			High			Low			High
Electric	$	1.29		$	1.29		$	1.32		$	1.27		$	1.30		$	1.24		$	1.27
Manufacturing	$	0.11		$	0.11		$	0.15		$	0.14		$	0.18		$	0.16		$	0.20
Plastics	$	0.32		$	0.26		$	0.30		$	0.24		$	0.28		$	0.24		$	0.28
Corporate	$	(0.16	)	$	(0.16	)	$	(0.12	)	$	(0.15	)	$	(0.11	)	$	(0.14	)	$	(0.10	)
Total – Continuing Operations	$	1.56		$	1.50		$	1.65		$	1.50		$	1.65		$	1.50		$	1.65
Expected Return on Equity					9.3	%		10.2	%		9.3	%		10.2	%		9.2	%		10.1	%

Contributing to our earnings guidance for 2016 are the following items:

We now expect 2016 Electric segment net income to be comparable with 2015 segment net income based on:

Normalized weather for the remainder of 2016. Mild weather in the first nine months of 2016 has had a negative impact on diluted earnings per share of approximately $0.05 compared to our original 2016 expected earnings based on normal temperatures and $0.04 compared to the nine months ended September 30, 2015.

Constructive outcome of the rate case filed in Minnesota in February 2016. We are currently receiving revenues under interim rates (subject to refund) related to this rate case. The Minnesota Public Utilities Commission determines our rates. Our ability to obtain final rates similar to interim rates and reasonable rates of return depends on regulatory action under applicable statutes and regulations. We cannot provide assurance our interim rates will become final and that our revised 10.05% requested return on equity will ultimately be approved. Through September of 2016, OTP revenue has increased $4.6 million as a result of the interim rate increase, which includes $6.9 million billed and accrued under interim rates net of a $2.3 million provision for an estimated refund related to a modification in OTP’s original request and other expected outcomes in the rate case. Compared to our original 2016 expected earnings, the refund provision has had a negative impact on diluted earnings per share of approximately $0.04 through September 30, 2016 and projected to be $0.06 by year-end 2016.

Rider recovery increases, including environmental riders in Minnesota, North Dakota and South Dakota related to the Big Stone AQCS environmental upgrades and transmission riders related to the Electric segment’s continuing investments in its share of the MISO-designated MVPs in South Dakota.

Meeting forecasted sales to pipeline and commercial customers.

A decrease in pension costs as a result of an increase in the discount rate from 4.35% to 4.76%.

offset by:

The effect of the 2015 adoption of bonus depreciation for income taxes reducing projected earnings from Electric segment operations by $0.06 per share in 2016.

Higher depreciation and property tax expenses due to large capital projects being put into service.

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

Increased operating expenses associated with reagents.

Increased transmission expenses associated with termination of historic integrated transmission agreements.

Higher post-retirement and post-employment medical costs than initially expected for 2016 due to changes in actuarial estimates and increased claims in 2016.

We are increasing our guidance for 2016 net income from our Manufacturing segment based on positive results through the first nine months of the year driven by improved productivity, despite softening end markets, and continued focus on improved productivity and cost reductions for the remainder of the year.

In spite of softening end markets, we expect 2016 net income from our Manufacturing segment to increase over 2015 by $3.0 million due to:

Increased sales volume at BTD as a result of having BTD-Georgia in place for a full year. Full year sales for BTD-Georgia are estimated to be $25 million compared with original expectations of $33 million. The decline is due to continued softness in end markets served by the BTD-Georgia location.

Improved margins on product mix that occurred in the second quarter and improved margins on parts and tooling sales driven by improved productivity as a result of lower expediting costs, costs of quality and maintenance expenses in our Illinois and Minnesota plants.

offset by:

An expected decline in revenue, excluding the full year impact of BTD-Georgia revenues, of approximately 4%, compared with an original growth expectation of 7%. This change is due to challenging market conditions impacting end markets served by BTD, which has significant exposure to agriculture, oil and gas and recreational vehicle end markets. All of these end markets are forecasted to be down in 2016 compared to 2015.

Continued challenges of on time deliveries, low productivity and end market softness at BTD-Georgia.

Higher facility costs associated with BTD’s expansion of its square footage at its Minnesota plants.

A decrease in earnings from T.O. Plastics mainly driven by an expected decrease in operating margins due to a shift in product mix relating to a customer bringing a product back into its own manufacturing facilities.

Backlog for the manufacturing companies of approximately $42 million for 2016 compared with $45 million one year ago.

We are maintaining our August guidance for 2016 net income from our Plastics segment. Net income for 2016 from this segment is expected to be down from 2015 with lower expected operating margins due to tighter spreads between raw material costs and sales prices, along with higher labor and freight costs.

We continue to expect lower corporate costs than originally estimated for 2016 due to continued cost reduction efforts.

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, warranty reserves 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 59 of our Annual Report on Form 10-K for the year ended December 31, 2015. There were no material changes in critical accounting policies or estimates during the quarter ended September 30, 2016.

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

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act. These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 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 2016. 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.

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.

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.

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 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 operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

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 our operating costs and the costs of supplying electricity to our customers.

Competition from foreign and domestic manufacturers, the price and availability of raw materials, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this segment.

We 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 our 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, 2016 we had exposure to market risk associated with interest rates because we had $50 million outstanding subject to a variable interest rate that is indexed to 30 day LIBOR plus 90 basis points under the Term Loan Agreement that terminates on February 5, 2018. OTP had $37.2 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 remaining consolidated long-term debt outstanding on September 30, 2016 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.

Item 4. Controls and Procedures

Under the supervision and with the participation of company management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our 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, 2016, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016.

During the fiscal quarter ended September 30, 2016, there were no changes in our 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, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are subject of various pending or threatened legal actions and proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable and an amount can be reasonably estimated. We believe 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 our consolidated financial position, results of operations or cash flows, excluding any liability for RSG charges described in Note 9 to the Company’s consolidated financial statements for which an estimate cannot be made at this time.

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 26 through 32 of our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 6. Exhibits

4.1

Note Purchase Agreement dated as of September 23, 2016, between Otter Tail Corporation and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on September 27, 2016).

4.2

Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, 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, 2016).

4.3

Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2016, 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, 2016).

10.1

1999 Employee Stock Purchase Plan, As Amended (2016).

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, 2016, 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 and Senior Vice President
		(Chief Financial Officer/Authorized Officer)

Dated: November 7, 2016

EXHIBIT INDEX

Exhibit Number		Description

4.1		Note Purchase Agreement dated as of September 23, 2016, between Otter Tail Corporation and the Purchasers named therein (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on September 27, 2016).

4.2		Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, 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, 2016).

4.3		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2016, 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, 2016).

10.1		1999 Employee Stock Purchase Plan, As Amended (2016).

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, 2016, 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.

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