Otter Tail Corp - FORM 10-Q

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EX-32.2 - EXHIBIT 32.2 - Otter Tail Corp	t1600488_ex32-2.htm
EX-32.1 - EXHIBIT 32.1 - Otter Tail Corp	t1600488_ex32-1.htm
EX-31.2 - EXHIBIT 31.2 - Otter Tail Corp	t1600488_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Otter Tail Corp	t1600488_ex31-1.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

June 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:

July 31, 2016 – 38,772,031 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.

Item 1.	Financial Statements

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

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

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

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

	Condensed Notes to Consolidated Financial Statements (not audited)	7-31

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31-50

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	50

Part II. Other Information

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 6.	Exhibits	51

Signatures		51

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

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

Assets

Current Assets
Cash and Cash Equivalents	$	—	$	—
Accounts Receivable:
Trade—Net		78,677		62,974
Other		7,144		9,073
Inventories		81,396		85,416
Unbilled Revenues		15,909		17,869
Income Taxes Receivable		—		4,000
Regulatory Assets		17,205		18,904
Other		14,065		8,453
Total Current Assets		214,396		206,689

Investments		8,413		8,284
Other Assets		33,605		32,784
Goodwill		37,572		39,732
Other Intangibles—Net		15,639		15,673
Regulatory Assets		123,706		127,707

Plant
Electric Plant in Service		1,834,157		1,820,763
Nonelectric Operations		218,007		201,343
Construction Work in Progress		116,848		79,612
Total Gross Plant		2,169,012		2,101,718
Less Accumulated Depreciation and Amortization		740,440		713,904
Net Plant		1,428,572		1,387,814

Total Assets	$	1,861,903	$	1,818,683

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

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

Liabilities and Equity

Current Liabilities
Short-Term Debt	$	49,274		$	80,672
Current Maturities of Long-Term Debt		52,497			52,422
Accounts Payable		86,210			89,499
Accrued Salaries and Wages		14,774			16,182
Accrued Taxes		10,562			14,827
Other Accrued Liabilities		17,951			15,416
Liabilities of Discontinued Operations		1,868			2,098
Total Current Liabilities		233,136			271,116

Pensions Benefit Liability		95,520			104,912
Other Postretirement Benefits Liability		49,659			48,730
Other Noncurrent Liabilities		24,980			23,854

Commitments and Contingencies (note 9)

Deferred Credits
Deferred Income Taxes		217,523			207,669
Deferred Tax Credits		23,678			24,506
Regulatory Liabilities		77,915			77,432
Other		9,580			11,595
Total Deferred Credits		328,696			321,202

Capitalization
Long-Term Debt—Net		493,804			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—38,703,277 Shares; 2015—37,857,186 Shares		193,516			189,286
Premium on Common Shares		313,839			293,610
Retained Earnings		132,401			126,025
Accumulated Other Comprehensive Loss		(3,648	)		(3,898	)
Total Common Equity		636,108			605,023

Total Capitalization		1,129,912			1,048,869

Total Liabilities and Equity	$	1,861,903		$	1,818,683

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands, except share and per-share amounts)	2016		2015			2016		2015
Operating Revenues
Electric	$	97,918	$	90,927		$	210,903	$	204,460
Product Sales		105,564		97,226			198,821		186,534
Total Operating Revenues		203,482		188,153			409,724		390,994
Operating Expenses
Production Fuel - Electric		9,990		4,183			25,690		18,782
Purchased Power - Electric System Use		15,127		19,684			32,013		43,376
Electric Operation and Maintenance Expenses		38,981		37,754			78,999		75,281
Cost of Products Sold (depreciation included below)		80,949		74,986			153,588		146,484
Other Nonelectric Expenses		9,238		8,823			20,693		21,286
Depreciation and Amortization		18,525		14,661			36,814		29,196
Property Taxes - Electric		3,589		3,262			7,268		6,764
Total Operating Expenses		176,399		163,353			355,065		341,169

Operating Income		27,083		24,800			54,659		49,825

Interest Charges		7,976		7,702			15,970		15,445
Other Income		1,532		567			1,932		1,139
Income Before Income Taxes—Continuing Operations		20,639		17,665			40,621		35,519
Income Tax Expense—Continuing Operations		5,083		4,008			10,575		8,081
Net Income from Continuing Operations		15,556		13,657			30,046		27,438
Discontinued Operations
Income (Loss) - net of Income Tax Expense (Benefit) of $80, ($1,329), $100 and ($2,705) for the respective periods		119		(1,992	)		149		(4,064	)
Impairment Loss - net of Income Tax Benefit of $0 for the six months ended June 30, 2015		—		—			—		(1,000	)
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of ($280) and $4,536 for the three and six months ended June 30, 2015		—		(229	)		—		6,997
Net Income (Loss) from Discontinued Operations		119		(2,221	)		149		1,933
Net Income		15,675		11,436			30,195		29,371

Average Number of Common Shares Outstanding—Basic		38,179,371		37,433,318			38,058,157		37,338,218
Average Number of Common Shares Outstanding—Diluted		38,321,289		37,653,203			38,183,249		37,558,103

Basic Earnings (Loss) Per Common Share:
Continuing Operations	$	0.41	$	0.37		$	0.79	$	0.74
Discontinued Operations		—		(0.06	)		—		0.05
	$	0.41	$	0.31		$	0.79	$	0.79
Diluted Earnings (Loss) Per Common Share:
Continuing Operations	$	0.41	$	0.36		$	0.79	$	0.73
Discontinued Operations		—		(0.06	)		—		0.05
	$	0.41	$	0.30		$	0.79	$	0.78

Dividends Declared Per Common Share	$	0.3125	$	0.3075		$	0.6250	$	0.6150

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2016			2015			2016			2015
Net Income	$	15,675		$	11,436		$	30,195		$	29,371
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	)
Gains (Losses) Arising During Period		27			(37	)		100			(5	)
Income Tax (Expense) Benefit		(9	)		13			(35	)		3
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		18			(24	)		65			(5	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		155			207			309			411
Income Tax Expense		(63	)		(83	)		(124	)		(165	)
Pension and Postretirement Benefit Plans – net-of-tax		92			124			185			246
Total Other Comprehensive Income		110			100			250			241
Total Comprehensive Income	$	15,785		$	11,536		$	30,445		$	29,612

See accompanying condensed notes to consolidated financial statements.

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Six Months Ended June 30,
(in thousands)	2016			2015
Cash Flows from Operating Activities
Net Income	$	30,195		$	29,371
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Gain from Sale of Discontinued Operations		—			(6,997	)
Net (Income) Loss from Discontinued Operations		(149	)		5,064
Depreciation and Amortization		36,814			29,196
Deferred Tax Credits		(828	)		(939	)
Deferred Income Taxes		9,679			12,707
Change in Deferred Debits and Other Assets		2,680			11,470
Discretionary Contribution to Pension Plan		(10,000	)		(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		6,404			4,025
Allowance for Equity/Other Funds Used During Construction		(475	)		(576	)
Change in Derivatives Net of Regulatory Deferral		—			(123	)
Stock Compensation Expense—Equity Awards		828			1,126
Other—Net		(76	)		200
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(12,673	)		(5,918	)
Change in Inventories		4,218			3,400
Change in Other Current Assets		(1,043	)		1,913
Change in Payables and Other Current Liabilities		(5,441	)		(21,294	)
Change in Interest and Income Taxes Receivable/Payable		4,018			96
Net Cash Provided by Continuing Operations		64,151			52,721
Net Cash Provided by (Used in) Discontinued Operations		11			(10,966	)
Net Cash Provided by Operating Activities		64,162			41,755
Cash Flows from Investing Activities
Capital Expenditures		(79,158	)		(83,418	)
Net Proceeds from Disposal of Noncurrent Assets		1,080			2,628
Final Purchase Price Adjustment – BTD-Georgia Acquisition		1,500			—
Cash Used for Investments and Other Assets		(1,719	)		(5,763	)
Net Cash Used in Investing Activities - Continuing Operations		(78,297	)		(86,553	)
Net Proceeds from Sale of Discontinued Operations		—			32,765
Net Cash Used in Investing Activities - Discontinued Operations		—			(1,770	)
Net Cash Used in Investing Activities		(78,297	)		(55,558	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		(2,024	)		(947	)
Net Short-Term Debt (Repayments) Borrowings		(31,398	)		32,186
Proceeds from Issuance of Common Stock – net of Issuance Expenses		21,645			6,848
Payments for Retirement of Capital Stock		(104	)		(1,421	)
Proceeds from Issuance of Long-Term Debt		50,000			—
Short-Term and Long-Term Debt Issuance Expenses		(59	)		(4	)
Payments for Retirement of Long-Term Debt		(106	)		(99	)
Dividends Paid and Other Distributions		(23,819	)		(23,035	)
Net Cash Provided by Financing Activities – Continuing Operations		14,135			13,528
Net Cash Provided by Financing Activities – Discontinued Operations		—			322
Net Cash Provided by Financing Activities		14,135			13,850
Net Change in Cash and Cash Equivalents - Discontinued Operations		—			(47	)
Net Change in Cash and Cash Equivalents		—			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	—		$	—

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 six-month periods ended June 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 June 30, 2016 and December 31, 2015:

June 30, 2016 (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:
Corporate Debt Securities – Held by Captive Insurance Company			$	4,169
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				4,067
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		835
Total Assets	$	2,835	$	8,236
Liabilities:
Other Accrued Liabilities:
Derivative Liabilities – Forward Gasoline Purchase Contracts			$	87
Total Liabilities			$	87

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:

	June 30,		December 31,
(in thousands)	2016		2015
Finished Goods	$	22,978	$	25,971
Work in Process		12,133		12,821
Raw Material, Fuel and Supplies		46,285		46,624
Total Inventories	$	81,396	$	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) June 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 June 30, 2016 and December 31, 2015:

June 30, 2016 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,310	$	15,181	42-230 months
Covenant not to Compete		590		164		426	26 months
Other Intangible Assets		639		607		32	3 months
Emission Allowances		—		NA		—	Expensed as used
Total	$	23,720	$	8,081	$	15,639

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				Six Months Ended
	June 30,				June 30,
(in thousands)	2016		2015		2016		2015
Amortization Expense – Intangible Assets	$	398	$	244	$	755	$	488

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 June 30,
(in thousands)	2016		2015
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	17,837	$	27,267

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 June 30, 2016 is $62.5 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2016 could be as high as $62.5 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. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

ASU 2015-03—In April 2015, the FASB issued ASU 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 97.3% of its operating revenues for the respective three-month periods ended June 30, 2016 and 2015, and 98.7% and 96.8% of its operating revenues for the respective six-month periods ended June 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 six-month periods ended June 30, 2016 and 2015 and total assets by business segment as of June 30, 2016 and December 31, 2015 are presented in the following tables:

Operating Revenue

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2016			2015			2016			2015
Electric	$	97,925		$	90,964		$	210,919		$	204,511
Manufacturing		58,452			51,273			118,272			108,032
Plastics		47,112			45,954			80,549			78,506
Intersegment Eliminations		(7	)		(38	)		(16	)		(55	)
Total	$	203,482		$	188,153		$	409,724		$	390,994

Interest Charges

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in thousands)	2016		2015		2016		2015
Electric	$	6,156	$	6,083	$	12,440	$	12,204
Manufacturing		1,006		846		1,998		1,678
Plastics		279		279		523		525
Corporate and Intersegment Eliminations		535		494		1,009		1,038
Total	$	7,976	$	7,702	$	15,970	$	15,445

Income Tax Expense—Continuing Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2016			2015			2016			2015
Electric	$	1,920		$	1,013		$	6,532		$	5,234
Manufacturing		1,791			1,157			2,810			1,661
Plastics		2,262			2,689			3,629			3,953
Corporate		(890	)		(851	)		(2,396	)		(2,767	)
Total	$	5,083		$	4,008		$	10,575		$	8,081

Net Income (Loss)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2016			2015			2016			2015
Electric	$	9,148		$	8,252		$	21,686		$	21,430
Manufacturing		3,009			1,912			4,862			3,096
Plastics		3,485			4,265			5,637			6,385
Corporate		(86	)		(772	)		(2,139	)		(3,473	)
Discontinued Operations		119			(2,221	)		149			1,933
Total	$	15,675		$	11,436		$	30,195		$	29,371

Identifiable Assets

	June 30,		December 31,
(in thousands)	2016		2015
Electric	$	1,553,563	$	1,520,887
Manufacturing		179,971		173,860
Plastics		89,058		81,624
Corporate		39,311		42,312
Total	$	1,861,903	$	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 June 30, 2016 was approximately $199 million.

Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—OTP has invested approximately $81 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 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 MVP’s 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 June 30, 2016 was approximately $43.0 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 June 30, 2016 was approximately $29.8 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 June 30, 2016
($ in thousands)	Test Year			3 Months Ended		6 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		$	2,850	$	2,850

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

Expected dates for next steps in the procedural schedule:

Intervenor direct testimony ─ due August 16, 2016

Public hearings ─ August 24 and 25, 2016

Evidentiary hearings ─ October 13-17, 2016

Report of administrative law judge (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 approximately 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. The proposed rate changes were to be effective on September 1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The MPUC granted an extension 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 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) 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.

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.

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 June 30,				Six Months Ended June 30,
Rate Rider (in thousands)	2016		2015		2016		2015
Minnesota
Conservation Improvement Program Costs and Incentives¹	$	2,209	$	1,610	$	4,715	$	3,538
Transmission Cost Recovery		1,133		1,212		3,409		2,827
Environmental Cost Recovery		3,153		2,600		6,235		5,157
North Dakota
Renewable Resource Adjustment		1,922		1,942		3,981		3,825
Transmission Cost Recovery		1,969		1,411		4,205		3,347
Environmental Cost Recovery		2,771		2,765		5,582		4,921
South Dakota
Transmission Cost Recovery		411		281		1,062		644
Environmental Cost Recovery		627		519		1,260		1,023
Conservation Improvement Program Costs and Incentives		124		90		283		230

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%. The FERC is expected to issue its order later in 2016. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issues its order in the ROE complaint proceeding.

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 hearing and hearings 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 reductions in revenue of $1.0 million and $0.2 million in the three-month periods ended June 30, 2016 and 2015, respectively, and $1.3 million and $0.8 million in the six-month periods ended June 30, 2016 and 2015, respectively, and has a $2.4 million liability on its balance sheet as of June 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, if FERC orders a reduction in the ROE component of the MISO Tariff.

4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations (ASC 980). This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	June 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	$	96,523	$	103,962	see below
Deferred Marked-to-Market Losses¹		4,063		8,499		12,562	54 months
Conservation Improvement Program Costs and Incentives²		1,313		6,016		7,329	24 months
Accumulated ARO Accretion/Depreciation Adjustment¹		—		5,911		5,911	asset lives
Big Stone II Unrecovered Project Costs – Minnesota¹		648		2,646		3,294	58 months
North Dakota Renewable Resource Rider Accrued Revenues²		1,894		684		2,578	21 months
Debt Reacquisition Premiums¹		351		1,364		1,715	195 months
Deferred Income Taxes¹		—		1,247		1,247	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up²		616		166		782	24 months
Big Stone II Unrecovered Project Costs – South Dakota²		100		593		693	83 months
Minnesota Deferred Rate Case Expenses Subject to Recovery¹		458		—		458	12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues²		323		—		323	12 months
Minnesota Renewable Resource Rider Accrued Revenues²		—		57		57	15 months
Total Regulatory Assets	$	17,205	$	123,706	$	140,911
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	76,196		76,196	asset lives
Refundable Fuel Clause Adjustment Revenues		2,619		—		2,619	12 months
Revenue for Rate Case Expenses Subject to Refund – Minnesota		712		563		1,275	22 months
Deferred Income Taxes		—		978		978	asset lives
North Dakota Transmission Cost Recovery Rider Accrued Refund		700		—		700	12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		644		—		644	12 months
Minnesota Transmission Cost Recovery Rider Accrued Refund		642		—		642	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		609		—		609	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		334		—		334	12 months
Other		31		92		123	210 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		—		86		86	24 months
Total Regulatory Liabilities	$	6,291	$	77,915	$	84,206
Net Regulatory Asset Position	$	10,914	$	45,791	$	56,705

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 June 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 June 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 195 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.

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.

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.

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.

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 June 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.

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 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 June 30, 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 June 30, 2016.

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of June 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 June 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 June 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 June 30, 2016 and December 31, 2015:

(in thousands)	June 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		(14,419	)		(16,070	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(14,419	)	$	(16,070	)

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

Loss Position (in thousands)	June 30, 2016		December 31, 2015
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	87	$	199
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade¹		14,332		15,871
Loss Contracts with No Ratings Triggers or Deposit Requirements		—		—
Loss Position	$	14,419	$	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	$	14,332	$	15,871
Offsetting Gains with Counterparties under Master Netting Agreements		—		—
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	14,332	$	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		4,249			19,486									23,735
Common Stock Retirements		(19	)		(85	)								(104	)
Net Income								30,195						30,195
Other Comprehensive Income											250			250
Employee Stock Incentive Plans Expense					828									828
Common Dividends ($0.625 per share)								(23,819	)					(23,819	)
Balance, June 30, 2016	$	193,516		$	313,839		$	132,401		$	(3,648	)	$	636,108

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 June 30, 2016:


Common Shares Outstanding, December 31, 2015	37,857,186
Issuances:
At-the-Market Offering	510,139
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	93,171
Cash Invested	69,740
Executive Stock Performance Awards (2013 and 2014 shares earned)	54,700
Employee Stock Purchase Plan:
Cash Invested	39,938
Dividends Reinvested	13,467
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, June 30, 2016	38,703,277

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 six-month periods ended June 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 June 30				Six Months ended June 30
	2016		2015		2016		2015
Weighted Average Common Shares Outstanding – Basic		38,179,371		37,433,318		38,058,157		37,338,218
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		91,381		141,540		69,133		141,540
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		39,374		45,060		39,608		45,060
Nonvested Restricted Shares		7,862		31,079		12,819		31,079
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,301		2,206		3,532		2,206
Total Dilutive Shares		141,918		219,885		125,092		219,885
Weighted Average Common Shares Outstanding – Diluted		38,321,289		37,653,203		38,183,249		37,558,103

The effect of dilutive shares on earnings per share for the three- and six-month periods ended June 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

On February 4, 2016 the following stock incentive awards were granted to the Company’s executive officers under the 2014 Stock Incentive Plan:

Award	Shares/ Units Granted		Grant-Date Fair Value per Award		Vesting
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

On April 11, 2016 the Company’s Board of Directors granted the following stock incentive awards to the Company’s non-employee directors and key employees under the 2014 Stock Incentive Plan:

Award	Shares/ Units Granted		Grant-Date Fair Value per Award		Vesting
Restricted Stock Granted to Nonemployee Directors		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

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 return on equity. 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).

The restricted stock units and shares of restricted stock vest 25% per year from the date of grant, and vesting 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 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 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 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 June 30, 2016 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.9 million (before income taxes) which will be amortized over a weighted-average period of 2.7 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three- and six-month periods ended June 30, 2016 and 2015 are presented in the table below:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2016		2015		2016		2015
Stock Performance Awards Granted to Executive Officers	$	304	$	37	$	841	$	1,057
Restricted Stock Units Granted to Executive Officers		64		127		309		380
Restricted Stock Granted to Executive Officers		22		144		51		301
Restricted Stock Granted to Directors		128		106		235		204
Restricted Stock Units Granted to Nonexecutive Employees		81		81		145		147
Employee Stock Purchase Plan (15% discount)		44		45		88		94
Totals	$	643	$	540	$	1,669	$	2,183

8. Retained Earnings Restriction

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

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends on a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of June 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 52.6% as of June 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 June 30, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $123.1 million.

Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. In May 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. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.

Contingencies

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million.

Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP has recorded a $2.4 million liability on its balance sheet as of June 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, if FERC orders a reduction in ROE component of the MISO Tariff.

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 in 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 disposition of a petition for a writ of certiorari seeking review by the U.S. Supreme Court, if such a writ is sought. Oral argument before all the judges of the D.C. Circuit (en banc review) is scheduled for September 2016. 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 matters pending as of June 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 June 30, 2016 and December 31, 2015:

(in thousands)	Line Limit		In Use on June 30, 2016		Restricted due to Outstanding Letters of Credit		Available on June 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	19,289	$	—	$	130,711	$	90,334
OTP Credit Agreement		170,000		29,985		50		139,965		148,694
Total	$	320,000	$	49,274	$	50	$	270,676	$	239,028

Debt Issuances and Retirements

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 June 30, 2016 and December 31, 2015:

June 30, 2016 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	29,985	$	19,289	$	49,274
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				145		145
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				908		908
Total	$	445,000	$	103,383	$	548,383
Less: Current Maturities net of Unamortized Debt Issuance Costs				52,497		52,497
Unamortized Long-Term Debt Issuance Costs		1,980		102		2,082
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	443,020	$	50,784	$	493,804
Total Short-Term and Long-Term Debt (with current maturities)	$	473,005	$	122,570	$	595,575

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 June 30,						Six Months Ended June 30,
(in thousands)	2016			2015			2016			2015
Service Cost—Benefit Earned During the Period	$	1,381		$	1,530		$	2,763		$	3,030
Interest Cost on Projected Benefit Obligation		3,521			3,347			7,043			6,672
Expected Return on Assets		(4,866	)		(4,592	)		(9,733	)		(9,192	)
Amortization of Prior-Service Cost:
From Regulatory Asset		47			47			94			94
From Other Comprehensive Income¹		1			1			2			2
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,227			1,705			2,454			3,338
From Other Comprehensive Income¹		32			46			63			86
Net Periodic Pension Cost	$	1,343		$	2,084		$	2,686		$	4,030
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 June 30,				Six Months Ended June 30,
(in thousands)	2016		2015		2016		2015
Service Cost—Benefit Earned During the Period	$	63	$	47	$	126	$	94
Interest Cost on Projected Benefit Obligation		417		381		834		762
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4		8		8
From Other Comprehensive Income¹		10		9		19		19
Amortization of Net Actuarial Loss:
From Regulatory Asset		73		84		146		167
From Other Comprehensive Income²		111		150		223		301
Net Periodic Pension Cost	$	678	$	675	$	1,356	$	1,351
¹Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	4	$	8	$	8
Other Nonelectric Expenses		6		5		11		11
²Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	68	$	77	$	136	$	155
Other Nonelectric Expenses		43		73		87		146

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 June 30,						Six Months Ended June 30,
(in thousands)	2016			2015			2016			2015
Service Cost—Benefit Earned During the Period	$	305		$	273		$	611		$	648
Interest Cost on Projected Benefit Obligation		542			499			1,083			1,049
Amortization of Prior-Service Cost:
From Regulatory Asset		33			51			66			102
From Other Comprehensive Income¹		1			2			2			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		—			(48	)		—			—
From Other Comprehensive Income¹		—			(1	)		—			—
Net Periodic Postretirement Benefit Cost	$	881		$	776		$	1,762		$	1,802
Effect of Medicare Part D Subsidy	$	(258	)	$	(293	)	$	(515	)	$	(743	)
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 June 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.

	June 30, 2016						December 31, 2015
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Short-Term Debt		(49,274	)		(49,274	)		(80,672	)		(80,672	)
Long-Term Debt including Current Maturities		(546,301	)		(641,722	)		(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 June 30,						Six Months Ended June 30,
(in thousands)	2016			2015			2016			2015
Income Before Income Taxes – Continuing Operations	$	20,639		$	17,665		$	40,621		$	35,519
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		8,049			6,889			15,842			13,852
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,885	)		(1,656	)		(3,571	)		(3,710	)
Corporate Owned Life Insurance		(350	)		(40	)		(414	)		(120	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(213	)		(213	)		(425	)		(425	)
Employee Stock Ownership Plan Dividend Deduction		(157	)		(171	)		(315	)		(343	)
AFUDC Equity		(150	)		(125	)		(187	)		(225	)
Section 199 Domestic Production Activities Deduction		(94	)		(363	)		(198	)		(725	)
Investment Tax Credits		(87	)		(143	)		(175	)		(286	)
Other Items – Net		(30	)		(170	)		18			63
Income Tax Expense – Continuing Operations	$	5,083		$	4,008		$	10,575		$	8,081
Effective Income Tax Rate – Continuing Operations		24.6	%		22.7	%		26.0	%		22.8	%

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		—		—
Increases Related to Tax Positions for Current Year		26		86
Uncertain Positions Resolved During Year		—		—
Balance on June 30	$	494	$	308

The balance of unrecognized tax benefits as of June 30, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of June 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 June 30, 2016.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of June 30, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2012 for federal and North Dakota state income taxes and for tax years prior to 2013 for Minnesota state income taxes.

16. Discontinued Operations

On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor. 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 June 30,						For the Six Months Ended June 30,
(in thousands)	2016			2015			2016			2015
Operating Revenues	$	—		$	5,899		$	—		$	24,623
Operating Expenses		(199	)		9,209			(249	)		31,350
Goodwill Impairment Charge		—			—			—			1,000
Operating Income (Loss)		199			(3,310	)		249			(7,727	)
Other Deductions		—			(11	)		—			(42	)
Income Tax Expense (Benefit)		80			(1,329	)		100			(2,705	)
Net Income (Loss) from Operations		119			(1,992	)		149			(5,064	)
(Loss) Gain on Disposition Before Taxes		—			(509	)		—			11,533
Income Tax (Benefit) Expense on Disposition		—			(280	)		—			4,536
Net (Loss) Gain on Disposition		—			(229	)		—			6,997
Net Income (Loss)	$	119		$	(2,221	)	$	149		$	1,933

Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $2.1 million and $4.4 million in the three- and six-month periods ended June 30, 2015, respectively.

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

(in thousands)	June, 2016		December 31, 2015
Current Liabilities	$	1,868	$	2,098
Liabilities of Discontinued Operations	$	1,868	$	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		—			(115	)
Decrease in Warranty Estimates for Prior Years		(230	)		—
Warranty Reserve Balance, June 30	$	1,873		$	2,412

The warranty reserve balances as of June 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. Expenses associated with remediation activities of these companies could be substantial. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

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

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 six-month periods ended June 30, 2016 and 2015, followed by a discussion of changes in our consolidated financial position during the six months ended June 30, 2016 and our business outlook for the remainder of 2016.

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

Consolidated operating revenues were $203.5 million for the three months ended June 30, 2016 compared with
$188.2 million for the three months ended June 30, 2015. Operating income was $27.1 million for the three months ended June 30, 2016 compared with $24.8 million for the three months ended June 30, 2015. The Company recorded diluted earnings per share from continuing operations of $0.41 for the three months ended June 30, 2016 compared with $0.36 for the three months ended June 30, 2015, and total diluted earnings per share of $0.41 for the three months ended June 30, 2016 compared with $0.30 for the three months ended June 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 June 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)	June 30, 2016		June 30, 2015
Operating Revenues:
Electric	$	7	$	37
Nonelectric		—		1
Cost of Products Sold		—		4
Other Nonelectric Expenses		7		34

Electric

	Three Months Ended
	June 30,							%
(in thousands)	2016		2015		Change			Change
Retail Sales Revenues	$	85,985	$	79,504	$	6,481			8.2
Wholesale Revenues – Company Generation		859		214		645			301.4
Net Revenue – Energy Trading Activity		—		58		(58	)		(100.0	)
Other Revenues		11,081		11,188		(107	)		(1.0	)
Total Operating Revenues	$	97,925	$	90,964	$	6,961			7.7
Production Fuel		9,990		4,183		5,807			138.8
Purchased Power – System Use		15,127		19,684		(4,557	)		(23.2	)
Other Operation and Maintenance Expenses		38,981		37,754		1,227			3.2
Depreciation and Amortization		13,432		11,137		2,295			20.6
Property Taxes		3,589		3,262		327			10.0
Operating Income	$	16,806	$	14,944	$	1,862			12.5
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,048,718		993,516		55,202			5.6
Wholesale kwh Sales – Company Generation		37,163		8,379		28,784			343.5
Wholesale kwh Sales – Purchased Power Resold		—		5,517		(5,517	)		(100.0	)
Heating Degree Days		455		435		20			4.6
Cooling Degree Days		133		83		50			60.2

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

	Three Months ended June 30,
	2016			2015
Heating Degree Days		87.7	%		82.7	%
Cooling Degree Days		125.5	%		76.1	%

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 second quarter of 2015:

	Three Months ended June 30,
	2016 vs Normal		2015 vs Normal			2016 vs 2015
Impact on Diluted Earnings Per Share	$	0.000	$	(0.009	)	$	0.009

The $6.5 million increase in retail revenue includes:

	·	A $2.8 million increase in retail revenues related to a 9.56% interim rate increase (subject to refund) implemented in mid-April 2016 in conjunction with Otter Tail Power Company’s (OTP’s) 2016 Minnesota general rate increase request.

	·	A $0.7 million increase in Environmental Cost Recovery (ECR) rider revenues 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 $0.6 million increase in Transmission Cost Recovery (TCR) rider revenues related to increased investment in transmission plant.

	·	A $0.6 million increase in Conservation Improvement Program (CIP) cost recovery and incentive revenues.

	·	A $0.6 million increase in revenues from the recovery of fuel and purchased power costs mainly due to an increase in the cost of fuel per kwh generated for retail use.

	·	A $0.6 million increase in revenues related to increased retail kwh sales due to warmer weather in the second quarter of 2016, evidenced by cooling degree days that were 60.2% higher than in the second quarter of 2015 and 125.5% of normal.

A $0.5 million increase in revenue related to increased kwh sales unrelated to weather, mainly sales to pipeline customers.

Revenue from wholesale electric sales from company-owned generation increased $0.6 million while fuel costs for wholesale generation increased $0.5 million, resulting in a $0.1 million increase in wholesale revenue net of fuel costs.

Other electric revenues increased $0.9 million as a result of an increase in transmission service charges related to a regional transmission cooperative terminating its integrated transmission agreement (ITA) with Otter Tail Power Company and joining the Southwest Power Pool (SPP) beginning in 2016. Prior to termination, revenues and costs under the ITA were reflected on a net basis in other electric revenue. Under the current arrangement under the Midcontinent Independent System Operator, Inc. (MISO), revenues related to the cooperative’s use of OTP’s transmission system are included in other electric revenue and costs associated with OTP’s use of the cooperative’s transmission system are included in operating expense. The $0.9 million revenue increase above was offset by a $0.8 million increase in the accrual for an estimated refund obligation that would arise if FERC orders a reduction in the return on equity (ROE) component of the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) for revenues billed under the tariff from December 2013 through May 2016. This is related to the non-binding initial decision of the presiding administrative law judge on June 30, 2016 recommending a lower FERC-allowed ROE.

Production fuel costs increased $5.8 million as a result of a 109.7% increase in kwhs generated from our steam-powered and combustion turbine generators, mainly related to Big Stone Plant being fully operational in the second quarter of 2016 compared to being down for maintenance during the entire second quarter of 2015.

The cost of purchased power to serve retail customers decreased $4.6 million due to a 14.3% decrease in the cost per kwh purchased, combined with a 10.3% decrease in kwhs purchased. The decreased cost per kwh purchased was driven by lower wholesale energy prices in the second quarter of 2016 compared with the second quarter of 2015. The decrease in kwhs purchased was the result of increased availability and generation from company-owned resources.

Electric operating and maintenance expenses increased $1.2 million as a result of:

	·	A $0.8 million increase in transmission service charges related to incurring transmission expenses from SPP participants beginning in 2016 as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the SPP.

	·	A $0.3 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with federal power plant emission regulations.

A $0.8 million increase in CIP program expenditures, repair expenses related to June 2016 storms, software licensing and travel expenses.

offset by:

A $0.7 million reduction in labor benefit costs mainly related to a decrease in corporate expenses billed to OTP.

Depreciation expense increased $2.3 million due to the AQCS at Big Stone Plant being placed in service at the end of December 2015 along with increased investment in transmission plant with the final phases of the Fargo-Monticello and Brookings-Southeast Twin Cities 345-kilovolt (kV) transmission lines placed in service in 2015.

The $0.3 million increase in property tax expense is related to property additions in Minnesota and North Dakota in 2015.

Manufacturing

	Three Months Ended
	June 30,						%
(in thousands)	2016		2015		Change		Change
Operating Revenues	$	58,452	$	51,273	$	7,179		14.0
Cost of Products Sold		43,258		39,525		3,733		9.4
Operating Expenses		5,261		5,224		37		0.7
Depreciation and Amortization		4,128		2,633		1,495		56.8
Operating Income	$	5,805	$	3,891	$	1,914		49.2

The $7.2 million increase in revenues in our Manufacturing segment includes the following:

Revenues at BTD Manufacturing, Inc. (BTD) increased $7.8 million, including:

Revenues of $6.5 million in the second quarter of 2016 at BTD-Georgia, the plant we acquired in September 2015.

A $3.8 million increase in revenues mainly related to the production of wind tower components at BTD’s Illinois plant.

offset by:

A $2.5 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.

Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $0.6 million, reflecting:

A $0.9 million decrease 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.

offset by:

A $0.3 million increase in revenues from sales of horticultural containers.

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

Cost of products sold at BTD increased $3.5 million. This included $5.7 million in cost of products sold at BTD-Georgia in the second quarter of 2016, offset by a $2.2 million net decrease in cost of products sold at BTD’s other facilities. The $2.2 million decrease is related to the decrease in sales to recreational and agricultural product manufacturers and to productivity improvements, partially offset by an increase in costs of products sold at BTD’s Illinois plant.

Cost of products sold at T.O. Plastics increased $0.2 million.

Gross margins at BTD were positively impacted in the second quarter of 2016 by changes in customer product mix between quarters.

Operating expenses at BTD increased $0.4 million, primarily as a result of the BTD-Georgia acquisition.

Operating expenses at T.O. Plastics decreased $0.3 million as a result of decreases in incentive benefits and selling expenses.

The $1.5 million increase in depreciation and amortization expenses in our Manufacturing segment includes $0.8 million at BTD-Georgia in the second quarter of 2016 and a $0.7 million increase at BTD as a result of placing new assets in service in Minnesota in 2015 and 2016.

Plastics

	Three Months Ended
	June 30,							%
(in thousands)	2016		2015		Change			Change
Operating Revenues	$	47,112	$	45,954	$	1,158			2.5
Cost of Products Sold		37,691		35,465		2,226			6.3
Operating Expenses		2,464		2,405		59			2.5
Depreciation and Amortization		952		863		89			10.3
Operating Income	$	6,005	$	7,221	$	(1,216	)		(16.8	)

The $1.2 million increase in Plastic segment revenues is the result of a 19.2% increase in pounds of polyvinyl chloride (PVC) pipe sold, mostly offset by a 14.0% decrease in the price per pound of pipe sold. The Plastics segment reported increased sales in the western United States, Texas and Missouri. The decline in sales price per pound is due to softening sales prices as a result of lower raw material prices between the quarters. Cost of products sold increased $2.2 million due to the increase in sales volume, partially offset by a 10.9% decrease in the cost per pound of PVC pipe sold.

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
	June 30,							%
(in thousands)	2016		2015		Change			Change
Operating Expenses	$	1,520	$	1,228		292			23.8
Depreciation and Amortization		13		28		(15	)		(53.6	)

Corporate operating expenses increased $0.3 million between the quarters mainly related to an increase in employee benefit costs.

Interest Charges

The $0.3 million increase in interest charges in the three months ended June 30, 2016 compared with the three months ended June 30, 2015 is related to a $50 million increase in the average level of the Company’s consolidated variable rate short-term and long-term debt outstanding between the quarters.

Other Income

The $1.0 million increase in other income in the three months ended June 30, 2016 compared with the three months ended June 30, 2015 is mainly the result of the Company receiving $0.7 million in benefit proceeds from corporate-owned life insurance and recording $0.2 million in gains on the sale of low income housing investments in the second quarter of 2016.

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $1.1 million in the three months ended June 30, 2016 compared with the three months ended June 30, 2015, mainly as a result of a $3.0 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 three-month periods ended June 30:

(in thousands)	2016			2015
Income Before Income Taxes – Continuing Operations	$	20,639		$	17,665
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		8,049			6,889
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,885	)		(1,656	)
Corporate Owned Life Insurance		(350	)		(40	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(213	)		(213	)
Employee Stock Ownership Plan Dividend Deduction		(157	)		(171	)
AFUDC Equity		(150	)		(125	)
Section 199 Domestic Production Activities Deduction		(94	)		(363	)
Investment Tax Credits		(87	)		(143	)
Other Items – Net		(30	)		(170	)
Income Tax Expense – Continuing Operations	$	5,083		$	4,008
Effective Income Tax Rate – Continuing Operations		24.6	%		22.7	%

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 17.4% in the three months ended June 30, 2016 compared with the three months ended June 30, 2015 due to higher wind speeds. 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 June 30:

(in thousands)	2016			2015
Operating Revenues	$	—		$	5,899
Operating Expenses		(199	)		9,209
Operating Income (Loss)		199			(3,310	)
Other Deductions		—			(11	)
Income Tax Expense (Benefit)		80			(1,329	)
Net Income (Loss) from Operations		119			(1,992	)
Loss on Disposition Before Taxes		—			(509	)
Income Tax Benefit on Disposition		—			(280	)
Net Loss on Disposition		—			(229	)
Net Income (Loss)	$	119		$	(2,221	)

The above results for the three months ended June 30, 2016 include net income of $0.1 million from the Company’s former wind tower manufacturer related to reductions in warranty reserves for expired warranties. The above results for the three months ended June 30, 2015 include net losses from operations of $1.5 million from Foley and $0.5 million from our former waterfront equipment manufacturer related to a settlement of a warranty claim. Foley 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 second quarter 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 $2.1 million.

Comparison of the Six Months Ended June 30, 2016 and 2015

Consolidated operating revenues were $409.7 million for the six months ended June 30, 2016 compared with $391.0 million for the six months ended June 30, 2015. Operating income was $54.7 million for the six months ended June 30, 2016 compared with $49.8 million for the six months ended June 30, 2015. The Company recorded diluted earnings per share from continuing operations of $0.79 for the six months ended June 30, 2016 compared to $0.73 for the six months ended June 30, 2015 and total diluted earnings per share of $0.79 for the six months ended June 30, 2016 compared to $0.78 for the six months ended June 30, 2015.

Amounts presented in the segment tables that follow for operating revenues, cost of goods sold and other nonelectric operating expenses for the six-month periods ended June 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)	June 30, 2016		June 30, 2015
Operating Revenues:
Electric	$	16	$	51
Nonelectric		—		4
Cost of Products Sold		—		4
Other Nonelectric Expenses		16		51

Electric

	Six Months Ended
	June 30,							%
(in thousands)	2016		2015		Change			Change
Retail Sales Revenues	$	186,640	$	183,118	$	3,522			1.9
Wholesale Revenues – Company Generation		1,770		1,274		496			38.9
Net Revenue – Energy Trading Activity		—		185		(185	)		(100.0	)
Other Revenues		22,509		19,934		2,575			12.9
Total Operating Revenues	$	210,919	$	204,511	$	6,408			3.1
Production Fuel		25,690		18,782		6,908			36.8
Purchased Power – System Use		32,013		43,376		(11,363	)		(26.2	)
Other Operation and Maintenance Expenses		78,999		75,281		3,718			4.9
Depreciation and Amortization		26,915		22,201		4,714			21.2
Property Taxes		7,268		6,764		504			7.5
Operating Income	$	40,034	$	38,107	$	1,927			5.1
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		2,421,917		2,355,199		66,718			2.8
Wholesale kwh Sales – Company Generation		80,573		44,476		36,097			81.2
Wholesale kwh Sales – Purchased Power Resold		—		5,537		(5,537	)		(100.0	)
Heating Degree Days		3,254		3,759		(505	)		(13.4	)
Cooling Degree Days		133		83		50			60.2

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

	Six Months ended June 30,
	2016			2015
Heating Degree Days		82.6	%		94.5	%
Cooling Degree Days		125.5	%		76.1	%

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 six months of 2015:

	Six Months ended June 30,
	2016 vs Normal			2015 vs Normal			2016 vs 2015
Effect on Diluted Earnings Per Share	$	(0.042	)	$	(0.017	)	$	(0.025	)

The $3.5 million increase in retail revenue includes:

A $2.8 million increase in retail revenues related to a 9.56% interim rate increase (subject to refund) implemented in mid-April 2016 in conjunction with OTP's 2016 Minnesota general rate increase request.

A $2.1 million increase in revenues related to an increase in retail kwh sales, mainly to pipeline customers.

A $2.0 million increase in ECR rider revenues 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 $1.9 million increase in TCR rider revenues related to increased investment in transmission plant.

A $1.2 million net increase in CIP cost recovery and incentive revenues mainly related to recovery of increased program costs.

offset by:

A $4.9 million decrease in revenues from the recovery of fuel and purchased power costs mainly due to a 22.4% decrease in the price per kwh of purchased power for system use.

A $1.6 million decrease in revenues mainly related to reduced demand due to milder weather in the first quarter of 2016, evidenced by heating degree days that were 15.8% lower than the first quarter of 2015 and 81.9% of normal.

Revenue from wholesale electric sales from company-owned generation increased $0.5 million while fuel costs for wholesale generation increased $0.6 million, resulting in a $0.1 million decrease in wholesale revenue net of fuel costs.

Other electric revenues increased $2.6 million as a result of:

A $1.7 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 Capacity Expansion 2020 and MISO designated Multi-Value Project (MVP) investment costs and operating expenses.

A $0.9 million net increase in transmission service revenues related to changes in ITAs with regional transmission cooperatives with one of the cooperatives joining the SPP beginning in 2016 and terminating its ITA.

A $0.5 million increase in steam sales to an ethanol plant next to Big Stone plant as a result of Big Stone Plant being fully operational in the first six months of 2016 compared to being down for maintenance from March through July in 2015.

offset by:

A $0.5 million increase in the accrual for an estimated refund obligation that would arise if FERC orders a reduction in the ROE component of the MISO Tariff for revenues billed under the tariff from December 2013 through May 2016.

Production fuel costs increased $6.9 million as a result of a 29.1% increase in kwhs generated from our steam-powered and combustion turbine generators, mainly related to Big Stone Plant being fully operational in the first six 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 $11.4 million due to a 22.4% decrease in the cost per kwh purchased, combined with a 4.9% decrease in kwhs purchased. The decreased cost per kwh purchased was driven by lower market demand mainly resulting from the milder winter weather in 2016 and lower wholesale energy prices in the first six months of 2016 compared with the first six months of 2015.

Electric operating and maintenance expenses increased $3.7 million as a result of:

A $2.6 million increase in transmission service charges related to OTP incurring transmission expenses from SPP participants beginning in 2016 as a result of a regional transmission cooperative terminating its integrated transmission agreement with OTP and joining the SPP.

A $1.0 million increase in CIP program expenditures.

A $0.9 million increase in pollution control reagent costs at Big Stone Plant and Coyote Station related to compliance with federal power plant emission regulations.

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

offset by:

A $1.3 million reduction in labor benefit costs related to a decrease in corporate stock-based incentive expenses billed to OTP.

Depreciation expense increased $4.7 million mainly due to the AQCS at Big Stone Plant being placed in service at the end of 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

	Six Months Ended
	June 30,						%
(in thousands)	2016		2015		Change		Change
Operating Revenues	$	118,272	$	108,032	$	10,240		9.5
Cost of Products Sold		89,313		85,224		4,089		4.8
Operating Expenses		11,335		11,162		173		1.5
Depreciation and Amortization		7,964		5,225		2,739		52.4
Operating Income	$	9,660	$	6,421	$	3,239		50.4

The $10.2 million increase in revenues in our Manufacturing segment includes the following:

Revenues at BTD increased $11.7 million, including:

Revenues of $14.3 million in the first six months of 2016 at BTD-Georgia, the plant we acquired in September 2015.

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

A $1.4 million increase in revenues from tooling production and sales.

offset by:

An $8.8 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 $0.7 million decrease in revenues from sales of scrap metal due to a reduction in scrap metal prices.

Revenues at T.O. Plastics decreased $1.5 million, including:

A $2.0 million decrease 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.

offset by:

A $0.6 million increase in revenues from sales of horticultural containers.

The $4.1 million increase in cost of products sold in our Manufacturing segment includes the following:

Cost of products sold at BTD increased $4.6 million. This included $12.3 million in cost of products sold at BTD-Georgia in the first six months of 2016, offset by a $7.7 million net decrease in cost of products sold at BTD’s other facilities. The $7.7 million decrease is related to the decrease in sales to recreational and agricultural product manufacturers and to productivity improvements, partially offset by an increase in costs of products sold at BTD’s Illinois plant.

Cost of products sold at T.O. Plastics decreased $0.5 million related to the decrease in sales.

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

The $0.2 million increase in operating expenses in our Manufacturing segment includes the following:

Operating expenses at BTD increased $0.7 million, primarily due to $1.0 million in operating expenses incurred at BTD-Georgia in the first six months of 2016, offset by a $0.3 million decrease in operating expenses at BTD’s other facilities as a result of reductions in labor-related costs.

Operating expenses at T.O. Plastics decreased $0.6 million as a result of a $0.3 million decrease in selling expenses and a $0.3 decrease in incentive benefits.

The $2.7 million increase in depreciation and amortization expenses in our Manufacturing segment includes $1.6 million at BTD-Georgia in the first six months of 2016 and a $1.1 million increase at BTD as a result of placing new assets in service in Minnesota in 2015 and 2016.

Plastics

	Six Months Ended
	June 30,							%
(in thousands)	2016		2015		Change			Change
Operating Revenues	$	80,549	$	78,506	$	2,043			2.6
Cost of Products Sold		64,275		61,264		3,011			4.9
Operating Expenses		4,612		4,695		(83	)		(1.8	)
Depreciation and Amortization		1,910		1,711		199			11.6
Operating Income	$	9,752	$	10,836	$	(1,084	)		(10.0	)

The $2.0 million increase in Plastic segment revenues is the result of an 18.9% increase in pounds of PVC pipe sold, mostly offset by a 13.7% decrease in the price per pound of pipe sold. The Plastics segment reported increased sales in the western United States, Texas and Missouri. The decline in sales price per pound is due to softening sales prices as a result of lower raw material prices between the periods. Cost of products sold increased $3.0 million due to the increase in sales volume, partly offset by an 11.8% decrease in the cost per pound of PVC pipe sold.

Corporate

	Six Months Ended
	June 30,							%
(in thousands)	2016		2015		Change			Change
Operating Expenses	$	4,762	$	5,480	$	(718	)		(13.1	)
Depreciation and Amortization		25		59		(34	)		(57.6	)

Corporate operating expenses decreased $0.7 million, mainly due to a decrease in expenditures for contracted services.

Interest Charges

The $0.5 million increase in interest charges in the six months ended June 30, 2016 compared with the six months ended June 30, 2015 is related to a $57 million increase in the average level of the Company’s consolidated variable rate short-term and long-term debt outstanding between the periods.

Other Income

The $0.8 million increase in other income in the six months ended June 30, 2016 compared with the six months ended June 30, 2015 is mainly due to the Company receiving $0.7 million in benefit proceeds from corporate-owned life insurance in the second quarter of 2016.

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $2.5 million in the six months ended June 30, 2016 compared with the six months ended June 30, 2015 as a result of a $5.1 million increase in income from continuing operations before income taxes and a $0.5 million reduction in the Section 199 Domestic Production Activities Deduction between the periods. 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 six-month periods ended June 30:

(in thousands)	2016			2015
Income Before Income Taxes – Continuing Operations	$	40,621		$	35,519
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		15,842			13,852
Increases (Decreases) in Tax from:
Federal PTCs		(3,571	)		(3,710	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(425	)		(425	)
Corporate Owned Life Insurance		(414	)		(120	)
Employee Stock Ownership Plan Dividend Deduction		(315	)		(343	)
Section 199 Domestic Production Activities Deduction		(198	)		(725	)
AFUDC Equity		(187	)		(225	)
Investment Tax Credits		(175	)		(286	)
Other Items - Net		18			63
Income Tax Expense – Continuing Operations	$	10,575		$	8,081
Effective Income Tax Rate – Continuing Operations		26.0	%		22.8	%

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 3.2% in the six months ended June 30, 2016 compared with the six months ended June 30, 2015 due to lower wind speeds. 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 six-month periods ended June 30:

(in thousands)	2016			2015
Operating Revenues	$	—		$	24,623
Operating Expenses		(249	)		31,350
Goodwill Impairment Charge		—			1,000
Operating Income (Loss)		249			(7,727	)
Other Deductions		—			(42	)
Income Tax Expense (Benefit)		100			(2,705	)
Net Income (Loss) from Operations		149			(5,064	)
Gain on Disposition Before Taxes		—			11,533
Income Tax Expense on Disposition		—			4,536
Net Gain on Disposition		—			6,997
Net Income	$	149		$	1,933

The above results for the six months ended June 30, 2016 include net income of $0.1 million from the Company’s former wind tower manufacturer related to reductions in warranty reserves for expired warranties. The above results for the six months ended June 30, 2015 include net losses from operations of $3.9 million from Foley, $0.8 million from AEV, Inc. and $0.5 million from our former waterfront equipment manufacturer related to the settlement of a warranty claim in the second quarter of 2015 and net income of $0.1 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 six 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 June 30, 2016 and December 31, 2015:

(in thousands)	Line Limit		In Use on June 30, 2016		Restricted due to Outstanding Letters of Credit		Available on June 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	19,289	$	—	$	130,711	$	90,334
OTP Credit Agreement		170,000		29,985		50		139,965		148,694
Total	$	320,000	$	49,274	$	50	$	270,676	$	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 510,139 shares under this program in the second quarter of 2016 and paid commissions to JPMS of $198,000.

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 $64.2 million for the six months ended June 30, 2016 compared with cash provided by operating activities of $52.7 million for the six months ended June 30, 2015. Contributing to the $11.5 million increase in cash provided by operating activities of continuing operations between the periods was a $10.9 million decrease in cash used for working capital items. The $10.9 million decrease in cash used for working capital items between the periods includes:

An $11.8 million decrease in cash used for accounts payable at OTP, reflecting higher levels of payables in June 2016 for coal deliveries and transmission services and the payment, in January 2015, of large billings for coal transportation, coal and purchase power received in December 2014.

A $4.0 million refund of 2015 estimated tax payments received in the first quarter of 2016. 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.

offset by:

A $6.8 million decrease in cash related to an increase in accounts receivable, mainly due to an increase in receivables at BTD in 2016 as a result of increased business activity in the first six months of the year, longer payment terms for certain customers and customers holding payment until after the June 30, 2016 quarter end.

In continuing operations, net cash used in investing activities was $78.3 million for the six months ended June 30, 2016 compared with $86.6 million for the six months ended June 30, 2015. The $8.3 million decrease in cash used for investing activities includes:

A $4.4 million reduction in capital expenditures at BTD as work on BTD’s Minnesota expansion project was winding down and nearing completion in the first six months of 2016 compared to a high level of expenditures in the first six months of 2015.

A $4.0 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 six months of 2015, with no similar transactions in the first six months of 2016.

$1.5 million in cash received as a final purchase price adjustment in June 2016 in the BTD-Georgia acquisition, mainly related to the final determination and settlement of the value of working capital acquired in the acquisition.

offset by:

A $1.5 million decrease in cash from the disposal of noncurrent assets mainly related to a decrease in investments sold at our captive insurance company between the periods.

Investing activities of discontinued operations in the six months ended June 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 $14.1 million for the six months ended June 30, 2016 compared with $13.5 million for the six months ended June 30, 2015. Financing activities in the first six months of 2016 included $50 million in borrowings under a Term Loan Agreement and $21.6 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 $33.4 million in cash used to pay down short-term borrowings and checks written in excess of cash and $23.8 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 six months of 2016.

Net cash provided by financing activities in the first six months of 2015 included $32.2 million in short-term borrowings used, in part, to fund capital expenditures, and $6.8 million in net proceeds from the issuance of common stock under our various stock purchase and dividend reinvestment plans, offset by $23.0 million in common stock dividend payments, $1.4 million in common stock retirement payments and $0.9 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 anticipated capital expenditures and electric utility average rate base:

(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 calls 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 the recently extended 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 $37.0 million in the first six months of 2016. Our other purchase obligations increased $3.4 million in 2016, $29.5 million in 2017 and 2018 and $0.6 million in 2019, mainly as a result of additional purchase obligations entered into in the first six 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.

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 510,139 shares under this program in the second quarter of 2016 and paid commissions to JPMS of $198,000.

Short-Term Debt

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

(in thousands)	Line Limit		In Use on June 30, 2016		Restricted due to Outstanding Letters of Credit		Available on June 30, 2016		Available on December 31, 2015
Otter Tail Corporation Credit Agreement	$	150,000	$	19,289	$	—	$	130,711	$	90,334
OTP Credit Agreement		170,000		29,985		50		139,965		148,694
Total	$	320,000	$	49,274	$	50	$	270,676	$	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 29, 2015 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2019 to October 29, 2020. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of 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 29, 2015 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2019 to October 29, 2020. OTP can draw on this credit

facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

Long-Term Debt

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 June 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 and the Term Loan 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 June 30, 2016 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement and the Term Loan Agreement was 3.73 to 1.00.

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

Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of June 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 3.68 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 June 30, 2016 our ratio of interest-bearing debt to total capitalization was 0.48 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 economic challenges facing our Manufacturing and Plastics segments and strategies for improving future operating results. We expect capital expenditures for 2016 to be $175 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.

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 Revised May 2, 2016						2016 Guidance Revised August 8, 2016
Diluted Earnings Per Share				Low			High			Low			High			Low			High
Electric	$	1.29		$	1.29		$	1.32		$	1.29		$	1.32		$	1.27		$	1.30
Manufacturing	$	0.11		$	0.11		$	0.15		$	0.12		$	0.16		$	0.14		$	0.18
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	)	$	(0.15	)	$	(0.11	)
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	%		9.3	%		10.2	%

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:

	o	Normalized weather for the remainder of 2016. Mild weather in the first six months of 2016 has had a negative impact on diluted earnings per share of approximately $0.04 compared to projected earnings under normal temperatures and $0.03 compared to the six months ended June 30, 2015.

	o	Constructive outcome of a 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 MPUC 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 that our interim rates will become final and that our requested 10.4% ROE will ultimately be approved.

	o	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 MVPs in South Dakota.

	o	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.

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

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

	o	Increased operating expenses associated with reagents and employee expenses.

	o	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 May 2016 guidance for 2016 net income from our Manufacturing segment based on positive results in the first six months of 2016 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 due to:

	o	Increases in sales volume at BTD as a result of having BTD-Georgia in place for a full year. Full year sales for BTD-Georgia are now estimated to be $28 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 and improved margins on parts and tooling sales given improved productivity as a result of lower expediting costs, costs of quality and maintenance expenses.

offset by:

	o	Excluding the full year impact of BTD-Georgia, revenues are now expected to decline approximately 3%, compared with an original growth expectation of 7%. This change is due to challenging market conditions impacting end markets served by BTD. BTD has significant exposure to the agriculture, oil and gas and recreational vehicle end markets, all of which are forecasted to be down in 2016 compared to 2015.

	o	Higher facility costs associated with BTD’s expansion of its square footage.

	o	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 $81 million for 2016 compared with $85 million one year ago.

We are maintaining our May 2016 guidance for 2016 net income for 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 June 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 June 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. We had $19.3 million in short-term debt outstanding subject to variable interest rates that are indexed to LIBOR plus 1.75% under our $150 million revolving credit facility, and OTP had $30.0 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 June 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 June 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 June 30, 2016.

During the fiscal quarter ended June 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.

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 2. Unregistered Sales of Equity Securities and Use of Proceeds

We do not have a publicly announced stock repurchase program. The following table shows common shares of the Company that were surrendered to us by employees to pay taxes in connection with shares issued for incentive awards in April 2016 under our 1999 and 2014 Stock Incentive Plans:

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
April 2016		1,800	$	28.415
May 2016		—		—
June 2016		—		—
Total		1,800

Item 6. Exhibits

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 June 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: August 9, 2016

EXHIBIT INDEX

Exhibit Number		Description

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 June 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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