10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2018

OR

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

For the transition period from to

Commission file number            0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

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

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

866-410-8780

(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      

Yes  ☑     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 ☑       No ☐

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

Large accelerated filer ☑	Accelerated filer ☐
Non-accelerated filer ☐	Smaller reporting company ☐	Emerging growth company ☐
(Do not check if a smaller reporting company)

If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

Yes ☑    No ☐

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

April 30, 2018 – 39,651,236 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – March 31, 2018 and December 31, 2017 (not audited)	2 & 3
	Consolidated Statements of Income - Three Months Ended March 31, 2018 and 2017 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2018 and 2017 (not audited)	5
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2018 and 2017 (not audited)	6
	Condensed Notes to Consolidated Financial Statements (not audited)	7-32
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33-46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46
Part II. Other Information
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6.	Exhibits	47
Signatures		48

1

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	March 31, 2018		December 31, 2017
Assets
Current Assets
Cash and Cash Equivalents	$	1,121	$	16,216
Accounts Receivable:
Trade—Net		94,265		68,466
Other		7,109		7,761
Inventories		87,999		88,034
Unbilled Receivables		18,692		22,427
Income Taxes Receivable		--		1,181
Regulatory Assets		19,736		22,551
Other		11,210		12,491
Total Current Assets		240,132		239,127
Investments		8,648		8,629
Other Assets		35,763		36,006
Goodwill		37,572		37,572
Other Intangibles—Net		13,420		13,765
Regulatory Assets		125,667		129,576
Plant
Electric Plant in Service		1,986,385		1,981,018
Nonelectric Operations		219,942		216,937
Construction Work in Progress		153,963		141,067
Total Gross Plant		2,360,290		2,339,022
Less Accumulated Depreciation and Amortization		814,074		799,419
Net Plant		1,546,216		1,539,603
Total Assets	$	2,007,418	$	2,004,278

See accompanying condensed notes to consolidated financial statements.

2

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	March 31, 2018			December 31, 2017
Liabilities and Equity
Current Liabilities
Short-Term Debt	$	30,319		$	112,371
Current Maturities of Long-Term Debt		171			186
Accounts Payable		87,179			84,185
Accrued Salaries and Wages		14,806			21,534
Accrued Federal and State Income Taxes		984			--
Accrued Taxes		17,585			16,808
Regulatory Liabilities		5,119			9,688
Other Accrued Liabilities		9,940			11,389
Liabilities of Discontinued Operations		--			492
Total Current Liabilities		166,103			256,653
Pensions Benefit Liability		89,552			109,708
Other Postretirement Benefits Liability		70,040			69,774
Other Noncurrent Liabilities		23,482			22,769
Commitments and Contingencies (note 8)
Deferred Credits
Deferred Income Taxes		103,009			100,501
Deferred Tax Credits		21,025			21,379
Regulatory Liabilities		233,279			232,893
Other		2,935			3,329
Total Deferred Credits		360,248			358,102
Capitalization
Long-Term Debt—Net		589,943			490,380
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, 2018—39,626,594 Shares; 2017—39,557,491 Shares		198,133			197,787
Premium on Common Shares		341,841			343,450
Retained Earnings		174,209			161,286
Accumulated Other Comprehensive Loss		(6,133	)		(5,631	)
Total Common Equity		708,050			696,892
Total Capitalization		1,297,993			1,187,272
Total Liabilities and Equity	$	2,007,418		$	2,004,278

See accompanying condensed notes to consolidated financial statements.

3

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended March 31,
(in thousands, except share and per-share amounts)	2018			2017
Operating Revenues
Electric:
Revenues from Contracts with Customers	$	123,825		$	119,782
Changes in Accrued Revenues under Alternative Revenue Programs		(875	)		(1,239	)
Total Electric Revenues		122,950			118,543
Product Sales under Contracts with Customers		118,316			95,574
Total Operating Revenues		241,266			214,117
Operating Expenses
Production Fuel – Electric		18,706			16,382
Purchased Power - Electric		21,593			19,188
Electric Operation and Maintenance Expenses		39,475			37,277
Cost of Products Sold (depreciation included below)		88,785			75,277
Other Nonelectric Expenses		12,494			10,135
Depreciation and Amortization		18,763			17,854
Property Taxes – Electric		3,835			3,798
Total Operating Expenses		203,651			179,911
Operating Income		37,615			34,206
Interest Charges		7,372			7,462
Nonservice Cost Components of Postretirement Benefits		1,417			1,405
Other Income		1,183			553
Income Before Income Taxes – Continuing Operations		30,009			25,892
Income Tax Expense – Continuing Operations		3,794			6,363
Net Income from Continuing Operations		26,215			19,529
Income from Discontinued Operations – net of Income Tax Expense of $38 in 2017		--			56
Net Income	$	26,215		$	19,585
Average Number of Common Shares Outstanding—Basic		39,550,874			39,350,802
Average Number of Common Shares Outstanding—Diluted		39,863,682			39,640,725
Basic Earnings Per Common Share:
Continuing Operations	$	0.66		$	0.50
Discontinued Operations		--			--
	$	0.66		$	0.50
Diluted Earnings Per Common Share:
Continuing Operations	$	0.66		$	0.49
Discontinued Operations		--			--
	$	0.66		$	0.49
Dividends Declared Per Common Share	$	0.335		$	0.320

See accompanying condensed notes to consolidated financial statements. 

4

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended March 31,
(in thousands)	2018			2017
Net Income	$	26,215		$	19,585
Other Comprehensive (Loss) Income:
Unrealized Gains on Available-for-Sale Securities:
Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period		(110	)		--
Unrealized (Losses) Gains Arising During Period		(66	)		17
Income Tax Benefit (Expense)		37			(6	)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		(139	)		11
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10)		227			157
Income Tax Expense		(59	)		(63	)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act		(531	)		--
Pension and Postretirement Benefit Plans – net-of-tax		(363	)		94
Total Other Comprehensive (Loss) Income		(502	)		105
Total Comprehensive Income	$	25,713		$	19,690

See accompanying condensed notes to consolidated financial statements.

5

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Three Months Ended March 31,
(in thousands)	2018			2017
Cash Flows from Operating Activities
Net Income	$	26,215		$	19,585
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		--			(56	)
Depreciation and Amortization		18,763			17,854
Deferred Tax Credits		(354	)		(366	)
Deferred Income Taxes		2,901			4,512
Change in Deferred Debits and Other Assets		6,295			5,005
Discretionary Contribution to Pension Plan		(20,000	)		--
Change in Noncurrent Liabilities and Deferred Credits		(5,091	)		1,314
Allowance for Equity/Other Funds Used During Construction		(638	)		(170	)
Stock Compensation Expense—Equity Awards		1,146			1,150
Other—Net		(284	)		(5	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(25,047	)		(15,521	)
Change in Inventories		35			2,267
Change in Other Current Assets		2,334			(22	)
Change in Payables and Other Current Liabilities		(2,598	)		(13,986	)
Change in Interest and Income Taxes Receivable/Payable		1,163			(321	)
Net Cash Provided by Continuing Operations		4,840			21,240
Net Cash Used in Discontinued Operations		(200	)		(39	)
Net Cash Provided by Operating Activities		4,640			21,201
Cash Flows from Investing Activities
Capital Expenditures		(23,618	)		(30,113	)
Net Proceeds from Disposal of Noncurrent Assets		510			612
Cash Used for Investments and Other Assets		(719	)		(508	)
Net Cash Used in Investing Activities		(23,827	)		(30,009	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		2,338			7,999
Net Short-Term (Repayments) Borrowings		(82,052	)		16,293
Proceeds from Issuance of Common Stock – net of Issuance Expenses		--			1,958
Payments for Retirement of Capital Stock		(2,409	)		(1,759	)
Proceeds from Issuance of Long-Term Debt		100,000			--
Short-Term and Long-Term Debt Issuance Expenses		(433	)		--
Payments for Retirement of Long-Term Debt		(60	)		(3,057	)
Dividends Paid		(13,292	)		(12,626	)
Net Cash Provided by Financing Activities		4,092			8,808
Net Change in Cash and Cash Equivalents		(15,095	)		--
Cash and Cash Equivalents at Beginning of Period		16,216			--
Cash and Cash Equivalents at End of Period	$	1,121		$	--

See accompanying condensed notes to consolidated financial statements.

6

OTTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2017. Because of seasonal and other factors, the earnings for the three months ended March 31, 2018 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, 2017.

1. Summary of Significant Accounting Policies

Revenue Recognition

In May 2014 the Financial Accounting Standards Board (FASB) issued a major update to the Accounting Standards Codification (ASC), Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). The Company adopted the updates in ASC 606 effective January 1, 2018 on a modified retrospective basis but did not record a cumulative effect adjustment to retained earnings on application of the updates because the adoption of the updates in ASC 606 had no material impact on the timing of revenue recognition for the Company or its subsidiaries. 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.

Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not identified any contracts where the timing of revenue recognition will change as a result of the adoption of the updates in ASC 606. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.

In addition to recognizing revenue from contracts with customers under ASC 606, the Company also records adjustments to Electric segment revenues for amounts subject to future collection or refund under alternative revenue programs (ARPs) as defined in ASC Topic 980, Regulated Operations (ASC 980). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues—In the Electric segment, the Company recognizes revenue in two categories: (1) revenues from contracts with customers and (2) adjustments to revenues for amounts collectible or refundable under ARPs.

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

7

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning incentives or returns on investments subject to recovery under several ARP rate riders, including:

● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders.

● In North Dakota: TCR, ECR and RRA riders

● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders.

OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 for total revenues billed and accrued under ARP riders for the three-month periods ended March 31, 2018 and 2017.

Manufacturing Segment Revenues—Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped and adjusts the revenue for volume rebate variable pricing considerations the company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Plastics Segment Revenues—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl-chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. Billed amounts of revenue recognized are adjusted for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on shipped products, there is no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is also recognized over time as the pipe is stored.

See operating revenue table in note 2 to consolidated financial statements for a disaggregation of the Company’s revenues by business segment for the three-month periods ended March 31, 2018 and 2017.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according 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. 

8

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 hierarchical 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.

Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 and December 31, 2017:

March 31, 2018 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,220
Corporate Debt Securities – Held by Captive Insurance Company			$	5,341
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,779
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		870
Total Assets	$	2,090	$	7,120

December 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,285
Corporate Debt Securities – Held by Captive Insurance Company			$	5,373
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,787
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		823
Total Assets	$	2,108	$	7,160

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

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.

9

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 paid by the Coyote Station owners under the LSA reflects 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.

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. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2018 could be as high as $56.5 million, OTP’s 35% share of unrecovered costs.

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

	March 31,		December 31,
(in thousands)	2018		2017
Finished Goods	$	25,341	$	26,605
Work in Process		17,224		14,222
Raw Material, Fuel and Supplies		45,434		47,207
Total Inventories	$	87,999	$	88,034

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table indicates there were no changes to goodwill by business segment during the first three months of 2018:

(in thousands)	Gross Balance December 31, 2017		Accumulated Impairments		Balance (net of impairments) December 31, 2017		Adjustments to Goodwill in 2018		Balance (net of impairments) March 31, 2018
Manufacturing	$	18,270	$	--	$	18,270	$	--	$	18,270
Plastics		19,302		--		19,302		--		19,302
Total	$	37,572	$	--	$	37,572	$	--	$	37,572

10

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 March 31, 2018 and December 31, 2017:

March 31, 2018 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	9,277	$	13,214	21	-	209
Covenant not to Compete		590		508		82		5
Other		154		30		124		29
Total	$	23,235	$	9,815	$	13,420

December 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,994	$	13,497	24	-	212
Covenant not to Compete		590		459		131		8
Other		154		17		137		32
Total	$	23,235	$	9,470	$	13,765

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Amortization Expense – Intangible Assets	$	345	$	332

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

(in thousands)	2018		2019		2020		2021		2022
Estimated Amortization Expense – Intangible Assets	$	1,315	$	1,184	$	1,133	$	1,099	$	1,099

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2018		2017
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,451	$	10,811

New Accounting Standards Adopted

ASU 2014-09—In May 2014 the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The Company adopted the updates in ASC 606 effective January 1, 2018 on a modified retrospective basis. See disclosures above under Revenue Recognition.

ASU 2016-01—In January 2016 the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10) (ASU 2016-01). The amendments in ASU 2016-01 address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments and require equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. For the Company, the amendments in ASU 2016-01are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company adopted the updates in ASU 2016-01 in the first quarter of 2018, which resulted in changes in the fair value of equity instruments held as investments by the Company’s captive insurance company being classified in net income. The fair value of equity instruments held by the Company’s captive insurance company on March 31, 2018 were $1,220,000 and the amount of unrealized gains on those investments recorded in net income in the first quarter of 2018 was $87,000.

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ASU 2017-07—In March 2017 the FASB issued ASU No. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07), with the intent of improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic 715, Compensation—Retirement Benefits (ASC 715), does not prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does not require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets. The amendments in ASU 2017-07 require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period, which the Company has provided in the electric operation and maintenance and other nonelectric expense lines on its income statement. The other components of net benefit cost as defined in ASC 715 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has provided the amount of the non-service cost components of net periodic postretirement benefit costs in a separate line below interest expense on the face of its consolidated income statement. The amendments in ASU 2017-07 also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU 2017-07 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The amendments have been applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the Company’s consolidated income statements and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit cost in assets.

The majority of the Company’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs applicable to OTP, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all the components of net periodic pension costs as recoverable operating expenses. The Company has assessed the impact adoption of the amendments in ASU 2017-07 will have on its consolidated financial statements, financial position and results of operations and OTP has established regulatory assets to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under ASU 2017-07.

The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 that would have been recorded as regulatory assets if the amendments in ASU 2017-07 were applicable in 2017 were $0.8 million. The Company’s non-service costs components of net periodic postretirement benefit costs included in operating expense in 2017 and 2016 that will be reported in other income and deductions in the Company's 2018 annual report on Form 10-K after adoption of ASU 2017-07 were $5.6 million for 2017 and $5.1 million for 2016. Additional information on the allocation of postretirement benefit costs for the three-month periods ended March 31, 2018 and 2017 is provided in note 10 to these consolidated financial statements for the Company’s major benefit programs presented.

New Accounting Standards Pending Adoption

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 Generally Accepted Accounting Principles in the United States (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 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 has developed a list of all current leases outstanding and continues to review ASU 2016-02, identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and is 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.

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ASU 2017-04—In January 2017 the FASB issued ASU No. 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04), which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step 2, an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU 2017-04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.

ASU 2018-02—In February 2018 the FASB issued ASU No. 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). The amendments in ASU 2018-02, which are narrow in scope, allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the 2017 Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users. The amendments in ASU 2018-02 also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption of the amendments in ASU 2018-02 is permitted. The amendments in ASU 2018-02 can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company does not plan to adopt the amendments in ASU 2018-02 until the first quarter of 2019. On adoption, the Company will reclassify the $784,000 of income tax effects of the TCJA on the gross deferred tax amounts at the date of enactment of the TCJA related to items remaining in accumulated other comprehensive income from other comprehensive income to retained earnings so that the remaining gross deferred tax amounts related to items in other comprehensive income will reflect current effective tax rates.

2. Segment Information

Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. 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 Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

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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 plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

Plastics consists of businesses producing 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 2017. The Electric segment has one customer that provided 11.7% of 2017 Electric segment revenues. The Manufacturing segment has one customer that manufactures and sells recreational vehicles that provided 24.3% of 2017 Manufacturing segment revenues and one customer that manufactures and sells lawn and garden equipment that provided 12.0% of 2017 Manufacturing segment revenues. The Plastics segment has two customers that individually provided 20.6% and 17.8% of 2017 Plastics segment revenues. The loss of any one of these customers would have a significant negative impact on the financial position and results of operations of the respective business segment and the Company.

All of the Company’s long-lived assets are within the United States and 98.3% and 98.4% of its operating revenues for the respective three-month periods ended March 31, 2018 and 2017 came from sales within the United States.

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2018 and 2017 and total assets by business segment as of March 31, 2018 and December 31, 2017 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	109,180		$	106,454
Changes in Accrued ARP Revenues		(875	)		(1,239	)
Total Retail Sales Revenue		108,305			105,215
Wholesale Revenues – Company Generation		1,015			867
Other Revenues		13,645			12,469
Total Electric Segment Revenues	$	122,965		$	118,551
Manufacturing Segment:
Metal Parts and Tooling	$	56,927		$	48,078
Plastic Products		10,235			9,552
Other		1,500			787
Total Manufacturing Segment Revenues	$	68,662		$	58,417
Plastics Segment – Sale of PVC Pipe Products	$	49,653		$	37,157
Intersegment Eliminations	$	(14	)	$	(8	)
Total	$	241,266		$	214,117

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Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Electric	$	6,390	$	6,386
Manufacturing		554		554
Plastics		150		153
Corporate and Intersegment Eliminations		278		369
Total	$	7,372	$	7,462

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	2,098		$	6,062
Manufacturing		1,223			1,055
Plastics		2,414			1,390
Corporate		(1,941	)		(2,144	)
Total	$	3,794		$	6,363

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	16,668		$	15,560
Manufacturing		4,164			2,172
Plastics		6,844			2,437
Corporate		(1,461	)		(640	)
Discontinued Operations		--			56
Total	$	26,215		$	19,585

Identifiable Assets

	March 31,		December 31,
(in thousands)	2018		2017
Electric	$	1,686,255	$	1,690,224
Manufacturing		180,319		167,023
Plastics		97,953		87,230
Corporate		42,891		59,801
Total	$	2,007,418	$	2,004,278

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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 FERC, impacting OTP’s revenues in 2018 and 2017.

Major Capital Expenditure Projects

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This is a 345-kiloVolt (kV) transmission line that will extend 163 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., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized costs on this project as of March 31, 2018 were approximately $96.5 million, which includes assets that are 100% owned by OTP.

Big Stone South–Brookings MVP—This 345-kV transmission line extends 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–Minnesota, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties 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 was energized on September 8, 2017. OTP’s capitalized costs on this project as of March 31, 2018 were approximately $72.4 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

General Rates—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base decreased from 8.61% to 7.5056% and its allowed rate of return on equity decreased from 10.74% to 9.41%.

The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVPs will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 million was applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017. In addition to the interim rate refund, OTP will refund the difference between (1) amounts collected under its Minnesota ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. As of October 31, 2017, the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts are being refunded to Minnesota customers over a 12-month period through reductions in the Minnesota ECR and TCR rider rates in effect November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

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Minnesota Conservation Improvement Programs (MNCIP)—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On May 25, 2016 the MPUC adopted the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The model provides 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. The financial incentive is also limited to 40% of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019 spending.

Based on results from the 2017 MNCIP program year, OTP recognized a financial incentive of $2.6 million in 2017. The 2017 program resulted in an approximate 10% decrease in energy savings compared to 2016 program results. OTP requested approval for recovery of its 2017 MNCIP program costs not included in base rates, a $2.6 million financial incentive and an update to the MNCIP surcharge from the MPUC on March 31, 2018.

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 of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverts interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider. On March 22, 2018 oral arguments were made before the Minnesota Court of Appeals. A decision is anticipated by the end of the second quarter 2018. OTP believes the MPUC-ordered treatment conflicts with federal authority over interstate transmission of electricity in and with FERC electric transmission rates as set forth in the Federal Power Act of 1935, as amended (Federal Power Act).

Environmental Cost Recovery Rider— OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, effective with implementation of final rates in November 2017.

Renewable Resource Adjustment— Effective November 1, 2017, with the implementation of final rates in Minnesota, new rates were put into effect for the Minnesota RRA rider to address recovery of federal Production Tax Credits (PTCs) expiring on OTP’s wind farms in 2017 and 2018.

North Dakota

General Rates—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates of $13.1 million or 8.72%. The $13.1 million increase is net of reductions in North Dakota RRA, TCR and ECR rider revenues that will result from a lower allowed rate of return on equity and changes in allocation factors in the general rate case. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of return on equity of 10.30%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. OTP used the same rate of return on equity in the calculation of interim rates as the rate of return on equity used in its 2018 test-year rate request. In response to the reduction in the federal corporate tax rate under the TCJA, the NDPSC issued an order on February 27, 2018 reducing OTP’s annual revenue requirement for interim rates by $4.5 million to $8.3 million, effective March 1, 2018. On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $13.1 million to $7.1 million, a 4.8% annual increase. The $6.0 million decrease includes $4.8 million related to tax reform and $1.2 million related to other updates. OTP will continue to address the impacts of the TJCA in its current general rate case.

OTP’s most recently approved 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%.

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Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.

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.

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS) projects. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s North Dakota share of reagent and emission allowance costs.

South Dakota

General Rates—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. OTP requested an interim rate increase effective May 21, 2018 while the SDPUC considers OTP’s overall request. The SDPUC is scheduled to review the application and act on the request for interim rates on May 15, 2018. The full effects of the TCJA on South Dakota revenue requirements will be addressed in OTP’s current general rate case and incorporated into final rates at the conclusion of that case. The second step in the request is an additional 1.7% increase to be effective January 1, 2020 to recover costs for a wind generation facility scheduled to be in service by the end of 2019.

OTP’s most recently approved 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.

Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

Reagent Costs and Emission Allowances—The SDPUC has approved the recovery of reagent and emission allowance costs in OTP’s South Dakota Fuel Clause Adjustment rider.

Revenues Recorded under Rate Riders

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

Rate Rider (in thousands)	2018			2017
Minnesota
Conservation Improvement Program Costs and Incentives1	$	2,516		$	1,966
Transmission Cost Recovery		(29	)		2,170
Environmental Cost Recovery		(31	)		2,824
Renewable Resource Recovery		525			--
North Dakota
Renewable Resource Adjustment		1,967			1,770
Transmission Cost Recovery		2,062			2,511
Environmental Cost Recovery		1,821			2,488
South Dakota
Transmission Cost Recovery		536			441
Environmental Cost Recovery		520			597
Conservation Improvement Program Costs and Incentives		229			240
Total	$	10,116		$	15,007

¹Includes MNCIP costs recovered in base rates.

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Rate Rider Updates

The following table provides summary information on the status of updates since January 1, 2016 for the rate riders described above:

Rate Rider	R - Request Date A - Approval Date	Effective Date Requested or Approved	Annual Revenue ($000s)			Rate
Minnesota
Conservation Improvement Program
2017 Incentive and Cost Recovery	R – March 31, 2018	October 1, 2018	$	10,400		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
2015 Incentive and Cost Recovery	A – July 19, 2016	October 1, 2016	$	8,590		$0.00275/kwh
Transmission Cost Recovery
2017 Rate Reset1	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	4,736		Various
2015 Annual Update	A – March 9, 2016	April 1, 2016	$	7,203		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of base
Renewable Resource Adjustment
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	9,650		7.493% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	9,989		7.756% of base
2016 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.005% of base
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7.573% of base
Transmission Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,469		Various
2017 Annual Update	A – November 29, 2017	January 1, 2018	$	7,959		Various
2016 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
Environmental Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,718		5.593% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	8,537		6.629% of base
2017 Annual Update	A – July 12, 2017	August 1, 2017	$	9,917		7.633% of base
2016 Annual Update	A – June 22, 2016	July 1, 2016	$	10,359		7.904% of base
South Dakota
Transmission Cost Recovery
2017 Annual Update	A – February 28, 2018	March 1, 2018	$	1,779		Various
2016 Annual Update	A – February 17, 2017	March 1, 2017	$	2,053		Various
2015 Annual Update	A – February 12, 2016	March 1, 2016	$	1,895		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh
2016 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh

¹Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

TCJA

The TCJA reduced the federal corporate income tax rate from 35% to 21%. Currently, all OTP rates have been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC have all initiated dockets or proceedings to assess the impact of the lower income tax rates under the TCJA on electric rates and develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018 but has not made a determination on rate treatment. The SDPUC required initial comments by February 1, 2018 and indicated that revenues collected after December 31, 2017 would be subject to refund, pending determination of the impacts of the TCJA. As described above, OTP’s pending general rate cases in North Dakota and South Dakota reflect the impact of the TCJA. OTP has accrued refund liabilities for revenues collected under rates set to recover higher levels of federal income taxes than OTP is currently incurring under the lower federal tax rates in the TCJA. The accrued refund liabilities as of March 31, 2018 related to the tax rate reduction were $1.9 million in Minnesota, $0.8 million in North Dakota and $0.5 million in South Dakota.

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FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one-day suspension period, subject to ultimate approval by the FERC.

MVPs—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 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 sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. A number of parties requested rehearing of the September 2016 order and the requests are pending FERC action.

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. OTP is currently waiting for the issuance of a FERC order on the second complaint.

Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of March 31, 2018.

In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required. On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETOs complaint. If FERC were to act on a motion to dismiss, it would eliminate the refund obligation from the second complaint and the ROE from the first complaint would remain in effect.

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4. Regulatory Assets and Liabilities

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

	March 31, 2018								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	9,090	$	110,214		$	119,304		see below
Conservation Improvement Program Costs and Incentives2		5,313		3,468			8,781			30
Accumulated ARO Accretion/Depreciation Adjustment1		--		6,779			6,779		asset lives
Deferred Marked-to-Market Losses1		3,463		1,989			5,452			33
Big Stone II Unrecovered Project Costs – Minnesota1		657		1,467			2,124			37
Debt Reacquisition Premiums1		246		904			1,150			174
Big Stone II Unrecovered Project Costs – South Dakota1		100		417			517			62
North Dakota Deferred Rate Case Expenses Subject to Recovery1		374		--			374			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1		322		--			322			12
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1		--		196			196		asset lives
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker1		--		166			166		see below
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		133		--			133			21
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		--		67			67			21
Minnesota Deferred Rate Case Expenses Subject to Recovery1		38		--			38			1
Total Regulatory Assets	$	19,736	$	125,667		$	145,403
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	148,938		$	148,938		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		84,223			84,223		asset lives
Refundable Fuel Clause Adjustment Revenues		2,414		--			2,414			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,161		--			1,161			7
North Dakota Renewable Resource Recovery Rider Accrued Refund		371		--			371			9
North Dakota Environmental Cost Recovery Rider Accrued Refund		351		--			351			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		317		--			317			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		304		--			304			7
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		68		36			104			21
Other		6		82			88			189
South Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		37		--			37			7
Revenue for Rate Case Expenses Subject to Refund – Minnesota		30		--			30			1
Total Regulatory Liabilities	$	5,119	$	233,279		$	238,398
Net Regulatory Asset/(Liability) Position	$	14,617	$	(107,612	)	$	(92,995	)

¹Costs subject to recovery excluding a rate of return.

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

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	December 31, 2017								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	9,090	$	112,487		$	121,577		see below
Conservation Improvement Program Costs and Incentives2		7,385		2,774			10,159			21
Accumulated ARO Accretion/Depreciation Adjustment1		--		6,651			6,651		asset lives
Deferred Marked-to-Market Losses1		4,063		2,405			6,468			36
Big Stone II Unrecovered Project Costs – Minnesota1		650		1,636			2,286			40
Debt Reacquisition Premiums1		254		960			1,214			177
Big Stone II Unrecovered Project Costs – South Dakota1		100		442			542			65
North Dakota Deferred Rate Case Expenses Subject to Recovery1		309		--			309			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1		75		--			75			12
North Dakota Renewable Resource Rider Accrued Revenues2		206		236			442			15
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		--		1,985			1,985			24
Minnesota Deferred Rate Case Expenses Subject to Recovery1		267		--			267			4
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		152		--			152			12
Total Regulatory Assets	$	22,551	$	129,576		$	152,127
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	149,052		$	149,052		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,100			83,100		asset lives
Refundable Fuel Clause Adjustment Revenues		5,778		--			5,778			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,667		--			1,667			11
South Dakota Environmental Cost Recovery Rider Accrued Refund		187		--			187			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		409		--			409			12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		132		48			180			24
Other		5		84			89			192
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		802		--			802			10
Revenue for Rate Case Expenses Subject to Refund – Minnesota		208		--			208			4
Minnesota Southwest Power Pool Transmission Cost Tracker Refund		--		609			609			22
North Dakota Transmission Cost Recovery Rider Accrued Refund		349		--			349			12
Total Regulatory Liabilities	$	9,688	$	232,893		$	242,581
Net Regulatory Asset/(Liability) Position	$	12,863	$	(103,317	)	$	(90,454	)

¹Costs subject to recovery excluding 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.

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.

All Deferred Marked-to-Market Losses recorded as of March 31, 2018 relate to forward purchases of energy scheduled for delivery through December 2020.

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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 174 months.

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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.

North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota and are currently being recovered beginning with the establishment of interim rates in January 2018.

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers.

The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied.

The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker relates to costs incurred, in excess of the rate at which the costs are being recovered under current rates, that are subject to future recovery under current rates or through future rate adjustments.

North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2018.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had not been billed to North Dakota customers as of December 31, 2017.

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.

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.

North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that had not been billed to North Dakota customers as of December 31, 2017.

The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.

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

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 March 31, 2018.

The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2018.

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 and for reagent and emission allowances costs that are recoverable from North Dakota customers as of March 31, 2018.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2018.

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The Minnesota Renewable Resource 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 March 31, 2018.

The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2018.

The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of March 31, 2018.

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 March 31, 2018.

The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund.

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. 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 Loss			Total Common Equity
Balance, December 31, 2017	$	197,787		$	343,450		$	161,286		$	(5,631	)	$	696,892
Common Stock Issuances, Net of Expenses		638			(638	)								--
Common Stock Retirements		(292	)		(2,117	)								(2,409	)
Net Income								26,215						26,215
Other Comprehensive Loss											(502	)		(502	)
Employee Stock Incentive Plans Expense					1,146									1,146
Common Dividends ($0.335 per share)								(13,292	)					(13,292	)
Balance, March 31, 2018	$	198,133		$	341,841		$	174,209		$	(6,133	)	$	708,050

Shelf Registrations and Common Share Distribution Agreement

On May 3, 2018 the Company 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 3, 2021. On May 3, 2018, the Company also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under the Company's Automatic Dividend Reinvestment (DRIP) and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the DRIP expires on May 3, 2021. The shelf registration statements replaced the Company’s prior shelf registration statements that were due to expire on May 11, 2018. On May 1, 2018 the Company’s Distribution Agreement with J.P. Morgan Securities (JPMS) ended as required under the agreement. This Distribution Agreement allowed the Company to offer and sell its common shares from time to time in an At-the-Market (ATM) offering program through JPMS, up to an aggregate sales price of $75 million. The Company expects to establish a new ATM offering program under which the Company may offer and sell its common shares from time to under the shelf registration statement.

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Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 through March 31, 2018:

Common Shares Outstanding, December 31, 2017	39,557,491
Issuances:
Executive Stock Performance Awards (2015 shares earned)	114,648
Vesting of Restricted Stock Units	12,950
Retirements:
Shares Withheld for Individual Income Tax Requirements	(58,495	)
Common Shares Outstanding, March 31, 2018	39,626,594

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three-month periods ended March 31, 2018 and 2017. 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 for the three-month periods ended March 31:

	2018		2017
Weighted Average Common Shares Outstanding – Basic		39,550,874		39,350,802
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		223,162		201,639
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		59,130		57,873
Nonvested Restricted Shares		27,643		27,069
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,873		3,342
Total Dilutive Shares		312,808		289,923
Weighted Average Common Shares Outstanding – Diluted		39,863,682		39,640,725

The effect of dilutive shares on earnings per share for the three-month periods ended March 31, 2018 and 2017, 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.

6. Share-Based Payments

Stock Incentive Awards

On February 5, 2018 the following stock incentive awards were granted to officers under the 2014 Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant- Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,200	$	41.325	25% per year through February 6, 2022
Stock Performance Awards Granted		54,000	$	35.73	December 31, 2020

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

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Under the performance share awards the aggregate award for performance at target is 54,000 shares. For target performance the participants would earn an aggregate of 27,000 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. The participants would also earn an aggregate of 27,000 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, 2018 through December 31, 2020, 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, 2018 and the average closing price for the 20 trading days immediately preceding January 1, 2021. Actual payment may range from zero to 150% of the target amount, or up to 81,000 common shares. There are no voting or dividend rights related to these awards until the shares, if any, are issued at the end of the performance measurement period. 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 an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.

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

As of March 31, 2018, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.9 million (before income taxes) which will be amortized over a weighted-average period of 2.2 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three-month periods ended March 31, 2018 and 2017 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2018		2017
Stock Performance Awards Granted to Executive Officers	$	651	$	649
Restricted Stock Units Granted to Executive Officers		249		264
Restricted Stock Granted to Executive Officers		16		22
Restricted Stock Granted to Directors		166		128
Restricted Stock Units Granted to Non-Executive Employees		64		87
Totals	$	1,146	$	1,150

7. Retained Earnings and Dividend Restriction

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

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of March 31, 2018, the Company was in compliance with these financial covenants. See note 9 to consolidated financial statements 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, the 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 47.4% and 58.0% based on OTP’s 2017 capital structure petition approved by order of the MPUC on September 1, 2017. As of March 31, 2018, OTP’s equity-to-total-capitalization ratio including short-term debt was 51.6% and its net assets restricted from distribution totaled approximately $481,000,000. Total capitalization for OTP cannot currently exceed $1,178,024,000.

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8. Commitments and Contingencies

Construction and Other Purchase Commitments

At March 31, 2018 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019 of approximately $37.5 million. At December 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019 of approximately $41.0 million. At March 31, 2018 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $6.2 million. At December 31, 2017 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $6.7 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 2041. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of 2019 and 2040, respectively. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant 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. In the first quarter of 2018, OTP entered into an agreement to lease rail cars for transporting coal to Hoot Lake Plant. The lease period runs from April 2018 through May 2021, increasing OTP’s commitments under operating leases by $243,000 in 2018, $324,000 in 2019, $324,000 in 2020 and $135,000 in 2021. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.

Contingencies

OTP had a $1.6 million refund liability on its balance sheet as of March 31, 2018 representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of the FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate.

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to not resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. Final briefs were filed on January 26, 2018. Oral arguments occurred on May 2, 2018. A final decision is anticipated in the summer of 2018. MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have an adverse effect on the Company’s results of operations.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

In 2014 the Environmental Protection Agency (EPA) published both proposed standards of performance for carbon dioxide (CO2) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed CO2 emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under Section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. Both rules were challenged on legal grounds. On February 9, 2016 the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on September 27, 2016 before the full court, and a decision was expected in the first half of 2017. However, pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth, the EPA was directed to consider suspending, revising

27

or rescinding the CO2 rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On October 16, 2017 the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.

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 March 31, 2018 will not be material.

9. Short-Term and Long-Term Borrowings

The following table presents the status of the Company’s lines of credit as of March 31, 2018 and December 31, 2017:

(in thousands)	Line Limit		In Use on March 31, 2018		Restricted due to Outstanding Letters of Credit		Available on March 31, 2018		Available on December 31, 2017
Otter Tail Corporation Credit Agreement	$	130,000	$	6,182	$	--	$	123,818	$	130,000
OTP Credit Agreement		170,000		24,137		300		145,563		57,239
Total	$	300,000	$	30,319	$	300	$	269,381	$	187,239

Debt Issuances

2018 Note Purchase Agreement

On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $100 million aggregate principal amount of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were used to repay outstanding borrowings under the OTP Credit Agreement.

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 so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the Note Purchase Agreement, any prepayment made by OTP of all of the Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.

The 2018 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities 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 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. The 2018 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 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP 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 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 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.

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The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2018 and December 31, 2017:

March 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	24,137	$	6,182	$	30,319
Long-Term Debt:
3.55% Guaranteed Senior Notes, due December 15, 2026			$	80,000	$	80,000
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
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048		100,000				100,000
North Dakota Development Note, 3.95%, due April 1, 2018				7		7
PACE Note, 2.54%, due March 18, 2021				644		644
Total	$	512,000	$	80,651	$	592,651
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		171		171
Unamortized Long-Term Debt Issuance Costs		2,091		446		2,537
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	509,909	$	80,034	$	589,943
Total Short-Term and Long-Term Debt (with current maturities)	$	534,046	$	86,387	$	620,433

December 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	112,371	$	--	$	112,371
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	--	$	--
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
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				27		27
PACE Note, 2.54%, due March 18, 2021				684		684
Total	$	412,000	$	80,711	$	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		186		186
Unamortized Long-Term Debt Issuance Costs		1,684		461		2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,316	$	80,064	$	490,380
Total Short-Term and Long-Term Debt (with current maturities)	$	522,687	$	80,250	$	602,937

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10. Pension Plan and Other Postretirement Benefits

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

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	1,615		$	1,407
Interest Cost on Projected Benefit Obligation		3,363			3,534
Expected Return on Assets		(5,300	)		(4,807	)
Amortization of Prior-Service Cost:
From Regulatory Asset		4			30
From Other Comprehensive Income1		--			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,784			1,273
From Other Comprehensive Income1		44			31
Net Periodic Pension Cost2	$	1,510		$	1,469
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of Costs:
Costs included in OTP capital expenditures	$	328		$	285
Service costs included in electric operation and maintenance expenses		1,247			1,100
Service costs included in other nonelectric expenses		40			34
Nonservice costs capitalized as regulatory assets		(21	)		--
Nonservice costs included in nonservice cost components of postretirement benefits		(84	)		50

Cash flows— The Company had no minimum funding requirement as of December 31, 2017 but made discretionary plan contributions totaling $20 million in the quarter ended March 31, 2018.

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

	Three Months Ended March 31,
(in thousands)	2018		2017
Service Cost—Benefit Earned During the Period	$	100	$	73
Interest Cost on Projected Benefit Obligation		399		422
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income1		10		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		67		71
From Other Comprehensive Income1		165		110
Net Periodic Pension Cost2	$	745	$	689
1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income.
2Allocation of Costs:
Service costs included in electric operation and maintenance expenses	$	25	$	24
Service costs included in other nonelectric expenses		75		49
Nonservice costs included in nonservice cost components of postretirement benefits		645		616

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

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	382		$	356
Interest Cost on Projected Benefit Obligation		645			678
Amortization of Net Actuarial Loss:
From Regulatory Asset		412			233
From Other Comprehensive Income1		10			6
Net Periodic Postretirement Benefit Cost2	$	1,449		$	1,273
Effect of Medicare Part D Subsidy	$	(37	)	$	(140	)
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of Costs:
Costs included in OTP capital expenditures	$	78		$	247
Service costs included in electric operation and maintenance expenses		294			278
Service costs included in other nonelectric expenses		10			9
Nonservice costs capitalized as regulatory assets		217			--
Nonservice costs included in nonservice cost components of postretirement benefits		850			739

11. Fair Value of Financial Instruments

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

Cash Equivalents—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 2018 and December 31, 2017 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.50% 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 fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

	March 31, 2018						December 31, 2017
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	1,121		$	1,121		$	16,216		$	16,216
Short-Term Debt		(30,319	)		(30,319	)		(112,371	)		(112,371	)
Long-Term Debt including Current Maturities		(590,114	)		(614,873	)		(490,566	)		(543,691	)

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13. Income Tax Expense – Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three-month periods ended March 31, 2018 and 2017:

	Three Months Ended March 31,
(in thousands)	2018			2017
Income Before Income Taxes – Continuing Operations	$	30,009		$	25,892
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017)		7,802			10,098
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,120	)		(2,052	)
Property Related Differences and Other Regulatory Adjustments		(1,073	)		105
Excess Tax Deduction – Equity Method Stock Awards		(624	)		(697	)
Other Comprehensive Income Deferred Tax Rate Adjustment		(531	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(212	)
Research and Development and Other Tax Credits		(180	)		(157	)
Allowance for Funds Used During Construction – Equity		(167	)		(67	)
Corporate Owned Life Insurance		(8	)		(294	)
Section 199 Domestic Production Activities Deduction		--			(330	)
Other Items – Net		(47	)		(31	)
Income Tax Expense – Continuing Operations	$	3,794		$	6,363
Effective Income Tax Rate – Continuing Operations		12.6	%		24.6	%

The following table summarizes the activity related to the Company’s unrecognized tax benefits:

(in thousands)	2018			2017
Balance on January 1	$	684		$	891
Decreases Related to Tax Positions for Prior Years		(44	)		--
Increases Related to Tax Positions for Current Year		36			43
Uncertain Positions Resolved During Year		--			--
Balance on March 31	$	676		$	934

The balance of unrecognized tax benefits as of March 31, 2018 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2018 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 March 31, 2018.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of May 1, 2018, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2014 for federal, Minnesota and North Dakota income taxes.

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

Results of Operations

Following is an analysis of the operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three months ended March 31, 2018 and 2017 followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2018 and our business outlook for the remainder of 2018.

Comparison of the Three Months Ended March 31, 2018 and 2017

Consolidated operating revenues were $241.3 million for the three months ended March 31, 2018 compared with $214.1 million for the three months ended March 31, 2017. Operating income was $37.6 million for the three months ended March 31, 2018 compared with $34.2 million for the three months ended March 31, 2017. The Company recorded diluted earnings per share from continuing operations and in total of $0.66 for the three months ended March 31, 2018 compared with $0.49 for the three months ended March 31, 2017.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three-month periods ended March 31, 2018 and 2017 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	March 31, 2018			March 31, 2017
Operating Revenues:
Electric	$	15		$	8
Nonelectric		(1	)		--
Costs of Products Sold		5			1
Other Nonelectric Expenses		9			7

Electric

	Three Months Ended
	March 31,									%
(in thousands)	2018			2017			Change			Change
Retail Sales Revenues from Contracts with Customers	$	109,180		$	106,454		$	2,726			2.6
Changes in Accrued Revenues under Alternative Revenue Programs		(875	)		(1,239	)		364			29.4
Total Retail Sales Revenue	$	108,305		$	105,215		$	3,090			2.9
Wholesale Revenues – Company Generation		1,015			867			148			17.1
Other Revenues		13,645			12,469			1,176			9.4
Total Operating Revenues	$	122,965		$	118,551		$	4,414			3.7
Production Fuel		18,706			16,382			2,324			14.2
Purchased Power – System Use		21,593			19,188			2,405			12.5
Other Operation and Maintenance Expenses		39,475			37,277			2,198			5.9
Depreciation and Amortization		13,922			13,066			856			6.6
Property Taxes		3,835			3,798			37			1.0
Operating Income	$	25,434		$	28,840		$	(3,406	)		(11.8	)
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,453,893			1,389,921			63,972			4.6
Wholesale kwh Sales – Company Generation		39,404			38,934			470			1.2
Heating Degree Days		3,591			3,082			509			16.5

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

	Three Months ended March 31,
	2018			2017
Heating Degree Days		106.6	%		90.1	%

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The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first quarters of 2018 and 2017 and between the quarters:

	2018 vs Normal		2017 vs Normal			2018 vs 2017
Effect on Diluted Earnings Per Share	$	0.022	$	(0.023	)	$	0.045

The $3.1 million increase in retail revenue includes:

● A $4.0 million increase in retail revenue related to the recovery of increased fuel and purchased power costs due to an increase in kwhs generated to serve retail customers.

● A $2.7 million increase in revenues related to increased usage due to colder weather in the first quarter of 2018, evidenced by a 16.5% increase in heating degree days between the quarters.

● A $1.6 million net retail revenue increase related to an interim rate increase implemented in North Dakota in January 2018 in conjunction with the 2017 general rate increase request.

● A $0.7 million increase in North Dakota and Minnesota Renewable Resource Adjustment rider revenues.

● A $0.4 million increase in Conservation Improvement Program (CIP) cost recovery revenues.

offset by:

● A $2.8 million reduction in revenues mainly related to the implementation of final retail rates in Minnesota that were lower than interim rates in effect in the first quarter of 2017.

● A $2.4 million reduction in revenues for the provision of refunds related to the recovery of federal income taxes in current retail electric rates in Minnesota and South Dakota that are in excess of lower federal income taxes under the 2017 Tax Cuts and Jobs Act (TCJA).

● A $0.7 million decrease in North Dakota and South Dakota Environmental Cost Recovery rider revenues mainly due to the reduction in the federal income tax rate under the TCJA and adjustment of the return on equity component of the rider in North Dakota to the level requested in 2017 general rate case.

● A $0.4 million decrease in North Dakota Transmission Cost Recovery rider revenues in correlation with the North Dakota general rate case initiated in November 2017 and the reduction in the federal income tax rate under the TCJA.

Other electric revenues increased $1.2 million due to an increase in Midcontinent Independent System Operator, Inc. (MISO) transmission tariff revenue resulting from increased transmission system investments and higher usage of company-owned transmission assets by others.

Production fuel costs increased $2.3 million, mainly due to a 31.4% increase in kwhs generated from our fuel burning plants to provide electricity for the increase in retail and wholesale demand driven by the colder weather in our service territory in the first quarter of 2018.

The cost of purchased power to serve retail customers increased $2.4 million due to a 14.2% increase in the cost per kwh purchased driven by higher market demand resulting from colder weather in the first quarter of 2018 compared with the first quarter of 2017.

Electric operating and maintenance expenses increased $2.2 million due to:

● A $1.5 million increase in operating expenses resulting primarily from lower capitalized labor, increased vegetation management costs and higher rate case expenses.

● A $0.4 million increase in CIP expenditures.

● A $0.3 million increase in transmission service charges. Transmission charges were lower in the first quarter of 2017 due to a $1.1 million MISO refund. The MISO refund related to a reduction in the return on equity component of the MISO tariff imposed from November 2013 through January 2015. This refund was offset by $0.8 million in Southwest Power Pool transmission cost true-ups recorded in the first quarter of 2017.

Depreciation expense increased $0.9 million mainly due to an increase in transmission project unitization and the Big Stone South-Brookings transmission line being placed in service in September 2017.

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Manufacturing

	Three Months Ended
	March 31,							%
(in thousands)	2018		2017		Change			Change
Operating Revenues	$	68,662	$	58,417	$	10,245			17.5
Cost of Products Sold		52,041		45,028		7,013			15.6
Operating Expenses		6,873		5,776		1,097			19.0
Depreciation and Amortization		3,854		3,857		(3	)		(0.1	)
Operating Income	$	5,894	$	3,756	$	2,138			56.9

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

● Revenues at BTD Manufacturing, Inc. (BTD) increased $9.6 million, including increases in parts sales of $5.2 million to manufacturers of industrial and construction equipment, $2.1 million to manufacturers of lawn and garden and agricultural equipment and $1.8 million to manufacturers of recreational vehicles. Revenues from scrap metal sales increased $0.5 million due to higher scrap volumes from increased production and a 12% increase in scrap metal pricing.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, improved $0.7 million due to increased sales of horticultural containers across its customer base.

The $7.0 million increase in cost of products sold in our Manufacturing segment includes the following:

● Cost of products sold at BTD increased $6.4 million in relationship to increased parts sales.

● Cost of products sold at T.O. Plastics increased $0.6 million related to the increase in product sales.

The $1.1 million increase in operating expenses in our Manufacturing segment includes a $1.0 million increase in expenses at BTD due to a $0.5 million increase in incentives earned on higher sales and $0.5 million in increased computer and software, contracted services and other administrative and general expenses. Operating expenses at T.O. Plastics increased $0.1 million quarter over quarter.

Plastics

	Three Months Ended
	March 31,						%
(in thousands)	2018		2017		Change		Change
Operating Revenues	$	49,653	$	37,157	$	12,496		33.6
Cost of Products Sold		36,749		30,250		6,499		21.5
Operating Expenses		2,614		2,028		586		28.9
Depreciation and Amortization		951		923		28		3.0
Operating Income	$	9,339	$	3,956	$	5,383		136.1

Plastics segment revenues increased $12.5 million due to a 20.7% increase in polyvinyl-chloride (PVC) pipe prices and a 10.7% increase in pounds of PVC pipe sold. The increase in revenue was partially offset by a $6.5 million increase in cost of products sold due to the increase in sales volume and a 9.8% increase in costs per pound of pipe sold. The increase in pipe prices in excess of the increase in cost of products sold resulted in a $6.0 million increase in gross margin on pipe sold. Plastics segment operating expenses increased by $0.6 million due to an increase in incentives earned and commissions paid on higher sales.

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Corporate

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

	Three Months Ended
	March 31,						%
(in thousands)	2018		2017		Change		Change
Operating Expenses	$	3,016	$	2,338	$	678		29.0
Depreciation and Amortization		36		8		28		350.0

Corporate operating expenses increased $0.7 million, mainly as a result of a $0.3 million increase in professional services and dues expenses and a $0.3 million increase in employee benefit costs.

Other Income

The $0.6 million increase in other income in the three months ended March 31, 2018 compared with the three months ended March 31, 2017 is mostly due to $0.5 million increase in the allowance for equity funds used during construction (AFUDC) in our Electric Segment resulting from an increase in construction work in progress subject to AFUDC.

Income Taxes – Continuing Operations

Income tax expense - continuing operations decreased $2.6 million in the three months ended March 31, 2018 compared with the three months ended March 31, 2017 mainly due to the reduction in the federal income tax rate from 35% to 21% under the TCJA resulting in a $3.6 million reduction in income tax expense. The decrease due to the federal income tax rate reduction was partially offset by $1.1 million increase in income tax expense resulting from a $4.1 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 March 31, 2018 and 2017:

	Three Months Ended March 31,
(in thousands)	2018			2017
Income Before Income Taxes – Continuing Operations	$	30,009		$	25,892
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017)		7,802			10,098
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,120	)		(2,052	)
Property Related Differences and Other Regulatory Adjustments		(1,073	)		105
Excess Tax Deduction – Equity Method Stock Awards		(624	)		(697	)
Other Comprehensive Income Deferred Tax Rate Adjustment		(531	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(212	)
Research and Development and Other Tax Credits		(180	)		(157	)
Allowance for Funds Used During Construction – Equity		(167	)		(67	)
Corporate Owned Life Insurance		(8	)		(294	)
Section 199 Domestic Production Activities Deduction		--			(330	)
Other Items – Net		(47	)		(31	)
Income Tax Expense – Continuing Operations	$	3,794		$	6,363
Effective Income Tax Rate – Continuing Operations		12.6	%		24.6	%

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 49.3% in the three months ended March 31, 2018 compared with the three months ended March 31, 2017 due to the PTC eligibility period ending for one of OTP’s wind farms. 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.

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Financial Position

The following table presents the status of our lines of credit as of March 31, 2018 and December 31, 2017:

(in thousands)	Line Limit		In Use on March 31, 2018		Restricted due to Outstanding Letters of Credit		Available on March 31, 2018		Available on December 31, 2017
Otter Tail Corporation Credit Agreement	$	130,000	$	6,182	$	--	$	123,818	$	130,000
OTP Credit Agreement		170,000		24,137		300		145,563		57,239
Total	$	300,000	$	30,319	$	300	$	269,381	$	187,239

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 3, 2018 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 3, 2021. On May 3, 2018, we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares until May 3, 2021, under the Company's Automatic Dividend Reinvestment (DRIP) and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. On May 1, 2018 our Distribution Agreement with J.P. Morgan Securities (JPMS) ended as required under the agreement. This Distribution Agreement allowed us to offer and sell our common shares from time to time in an At-the-Market (ATM) offering program through JPMS, up to an aggregate sales price of $75 million. We expect to establish a new ATM offering program to replace our prior program under which we may offer and sell our common shares from time to under the shelf registration statement.

Equity or debt financing will be required in the period 2018 through 2022 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 7 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 5, 2018 our board of directors increased the quarterly dividend from $0.32 to $0.335 per common share.

Cash provided by operating activities of continuing operations was $4.8 million for the three months ended March 31, 2018 compared with cash provided by operating activities of $21.2 million for the three months ended March 31, 2017. Primary reasons for the $16.4 million decrease in cash provided by continuing operations between the quarters were a $20.0 million increase in discretionary contributions to the Company’s funded pension plan, partially offset by a $6.6 million increase in net income from continuing operations. A $6.4 million increase in cash used for noncurrent liabilities and deferred credits was partially offset by a $3.5 million reduction in cash used for working capital items between the quarters. The $3.5 million decrease in cash used for working capital items between the quarters includes the following major items:

● An $11.4 million decrease in cash used for accounts payable in the Plastics segment related to a change in the timing of resin purchases and payments between the periods and an increase in resin purchases in the first quarter of 2018 compared with the first quarter of 2017 due to an increase in pipe production and sales between quarters.

offset by:

● Increases in cash used for accounts receivable of $7.1 million at BTD and $1.9 million at the plastic pipe companies related to increased sales and product prices at the respective companies in the first quarter of 2018 compared with the first quarter of 2017.

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Net cash used in investing activities was $23.8 million for the three months ended March 31, 2018 compared with $30.0 million for the three months ended March 31, 2017. The $6.2 million decrease in cash used for investing activities includes a $6.5 million decrease in capital expenditures, mainly due to a $7.2 million reduction in cash used for capital expenditures at OTP as the Big Stone South–Brookings 345 kiloVolt (kV) transmission line project, placed in service September 2017, was under construction during the first quarter of 2017. OTP work continues on the Big Stone South–Ellendale 345 kV transmission line project and on a major project to replace its customer information system.

Net cash provided by financing activities was $4.1 million for the three months ended March 31, 2018 compared with $8.8 million for the three months ended March 31, 2017. Financing activities in the first quarter of 2018 included proceeds from the issuance of $100 million in privately placed 4.07% Senior Unsecured Notes due February 7, 2048, which were used to pay down a portion of borrowings then outstanding under the OTP Credit Agreement. Additional borrowings under our credit agreements were used to fund a portion of first quarter 2018 capital expenditures. Common dividend payments of $13.3 million in the first quarter of 2018 contributed to the $15.1 million reduction in cash and cash equivalents during the quarter.

Financing activities in the first quarter of 2017 included a net increase in short-term and long-term borrowings of $13.2 million and an increase in checks issued in excess of cash of $8.0 million, which has a direct relationship with the increase in cash used for accounts payable in the operating section of the cash flow statement, partially offset by $12.6 million in common dividend payments.

CAPITAL REQUIREMENTS

2018-2022 Capital Expenditures

The following table shows our 2017 capital expenditures and 2018 through 2022 anticipated capital expenditures and electric utility average rate base:

(in millions)	2017		2018		2019		2020		2021		2022		Total
Capital Expenditures:
Electric Segment:
Renewables and Natural Gas Generation			$	1	$	308	$	102	$	50	$	1	$	462
Transformative Technology and Infrastructure				--		22		32		43		39		136
Transmission				45		12		9		7		7		80
Other				49		40		42		45		47		223
Total Electric Segment	$	119	$	95	$	382	$	185	$	145	$	94	$	901
Manufacturing and Plastics Segments		14		15		14		15		14		14		72
Total Capital Expenditures	$	133	$	110	$	396	$	200	$	159	$	108	$	973
Total Electric Utility Average Rate Base	$	1,055	$	1,091	$	1,297	$	1,480	$	1,568	$	1,625

The consolidated capital expenditure plan for the 2018-2022 time period calls for $973 million based on the need for additional wind and solar in rate base and capital spending for Astoria Station, a natural gas-fired plant that is expected to replace Hoot Lake Plant when it is retired in 2021. Given the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be 9.0% from 2017 through 2022. 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 2018 through 2022 timeframe.

On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (EDF) to purchase and assume the development assets associated with a 150-megawatt (MW) wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement is currently expected to close no earlier than mid-2018, pending regulatory reviews, satisfactory interconnection costs and other conditions. On the same day, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF that will be effective upon the closing of the Purchase Agreement pursuant to which EDF will construct the wind farm with a targeted completion date in 2019 for consideration of $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. The agreements contain representations, warranties, covenants and indemnities customary to transactions of this type and include provisions for liquidated damages to be paid by EDF in the event of certain occurrences described in the agreements. As of March 31, 2018, OTP had capitalized approximately $4.6 million in development costs associated with the Merricourt Project. A final order for an Advance Determination of Prudence (ADP), subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. On October 26, 2017 the MPUC approved the facility under the Renewable Energy Standard making the Merricourt Project eligible for cost recovery under the Minnesota Renewable Resource Recovery rider.

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In addition to the Merricourt Project, OTP is moving forward with plans for the development, construction and ownership of a 250-MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota (Astoria Station) as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. OTP expects the project will cost approximately $165 million. As of March 31, 2018, OTP had capitalized approximately $5.4 million in development costs associated with Astoria Station. A final order granting ADP for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations.

If a resource addition is determined to be prudent by the NDPSC, a public utility may recover in its rates for North Dakota customers, and in a timely manner consistent with the public utility's financial obligations, the jurisdictional share of amounts the public utility reasonably incurred or obligated on a prudent resource addition, including accrued allowance for funds used during construction, even though the resource addition may never be fully operational or used by the public utility to serve its North Dakota customers. The cost amortization period for a discontinued resource addition may not exceed five years from the date commencement of the recovery is approved by the NDPSC. No return on amounts incurred or obligated by the public utility may be authorized for the period after the resource addition is discontinued.

Contractual Obligations

In the first quarter of 2018 OTP entered into an agreement to lease rail cars for transporting coal to Hoot Lake Plant. As a result, our operating lease obligations reported in the table on page 50 of our Annual Report on Form 10-K for the year ended December 31, 2017 increased $0.2 million for 2018, $0.6 million for 2019 and 2020, and $0.1 million for 2021.

CAPITAL RESOURCES

On May 3, 2018 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 3, 2021. On May 3, 2018 we also filed a shelf registration statement with the SEC for the issuance of up to 1,500,000 common shares under our Automatic Dividend Reinvestment (DRIP) and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the DRIP expires on May 3, 2021. On May 1, 2018 our Distribution Agreement with JPMS ended. This Distribution Agreement allowed us to offer and sell our common shares from time to time in an ATM offering program through JPMS up to an aggregate sales price of $75 million. We expect to establish a new At-the-Market offering program to replace our prior program under which we may offer and sell our common shares from time to under the shelf registration statement.

Short-Term Debt

The following table presents the status of our lines of credit as of March 31, 2018 and December 31, 2017:

(in thousands)	Line Limit		In Use on March 31, 2018		Restricted due to Outstanding Letters of Credit		Available on March 31, 2018		Available on December 31, 2017
Otter Tail Corporation Credit Agreement	$	130,000	$	6,182	$	--	$	123,818	$	130,000
OTP Credit Agreement		170,000		24,137		300		145,563		57,239
Total	$	300,000	$	30,319	$	300	$	269,381	$	187,239

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2017 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2021 to October 31, 2022. 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 1.50%, subject to adjustment based on our senior unsecured credit ratings or the issuer rating if a rating is not provided for the senior unsecured credit. 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 

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Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2017 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2021 to October 31, 2022. 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 or the issuer rating if a rating is not provided for the 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

2018 Note Purchase Agreement

On November 14, 2017, OTP entered into a Note Purchase Agreement (the 2018 Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction, $100 million aggregate principal amount of OTP’s 4.07% Series 2018A Senior Unsecured Notes due February 7, 2048 (the 2018 Notes). The 2018 Notes were issued on February 7, 2018. Proceeds from the 2018 Notes were used to repay outstanding borrowings under the OTP Credit Agreement.

OTP may prepay all or any part of the 2018 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 so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2018 Note Purchase Agreement, any prepayment made by OTP of all of the 2018 Notes then outstanding on or after August 7, 2047 will be made without any make-whole amount. The 2018 Note Purchase Agreement also requires OTP to offer to prepay all outstanding 2018 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2018 Note Purchase Agreement) of OTP.

The 2018 Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities 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 2018 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2018 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 2018 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP 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 2018 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the 2018 Notes than any analogous provision contained in the 2018 Note Purchase Agreement (an Additional Covenant), then unless waived by the Required Holders (as defined in the 2018 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2018 Note Purchase Agreement. The 2018 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.

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2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under our Term Loan Agreement described below.

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

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and our Material Subsidiaries. These include restrictions on our and our Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on our and our Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our or our Material Subsidiaries’ credit ratings.

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). The notes were issued on February 27, 2014.

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 (as defined in the 2013 Note Purchase Agreement) 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 the OTP 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.

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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 (the 2011 Note Purchase Agreement). OTP also has outstanding its $122 million senior unsecured notes issued in three series consisting of $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). On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire its $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, which had been issued under the 2007 Note Purchase Agreement and matured on August 20, 2017.

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 March 31, 2018.

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 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of March 31, 2018, our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement and the 2016 Note Purchase Agreement was 4.62 to 1.00.

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

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

● Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of March 31, 2018, 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 3.51 to 1.00.

● Under the 2013 Note Purchase Agreement and the 2018 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, in each case as provided in the related agreement.

As of March 31, 2018, our ratio of Interest-bearing Debt to Total Capitalization was 0.47 to 1.00 on a consolidated basis and 0.48 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of March 31, 2018.

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OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $3.2 million, but our line of credit borrowing limits are only restricted by $0.3 million 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.

2018 BUSINESS OUTLOOK

We are raising our consolidated diluted earnings per share guidance for 2018 to be in the range of $1.90 to $2.05 from our previously announced guidance range of $1.80 to $1.95. The revised guidance is the result of stronger-than-expected first quarter results from our Plastics segment and reflects strategies for improving future operating results. We have taken into consideration the cyclical nature of some of our businesses as well as current regulatory factors and economic challenges facing our Electric, Manufacturing and Plastics segments. We expect capital expenditures for 2018 to be $110 million compared with actual cash used for capital expenditures of $133 million in 2017. Our planned expenditures for 2018 include $33 million for the Big Stone South-Ellendale transmission line project, which positively impacts earnings by providing an immediate return on invested funds through rider recovery mechanisms.

Segment components of our 2018 earnings per share guidance range compared with 2017 actual earnings are as follows:

	2017 EPS by		2018 Guidance February 12, 2018				2018 Guidance May 7, 2018
Diluted Earnings Per Share	Segment		Low		High		Low		High
Electric	$	1.24	$	1.34	$	1.37	$	1.34	$	1.37
Manufacturing	$	0.28	$	0.26	$	0.30	$	0.26	$	0.30
Plastics	$	0.54	$	0.36	$	0.40	$	0.48	$	0.52
Corporate	$	(0.25)	$	(0.16)	$	(0.12)	$	(0.18)	$	(0.14)
Total – Continuing Operations	$	1.81	$	1.80	$	1.95	$	1.90	$	2.05
Return on Equity		10.6%		10.1%		10.9%		10.6%		11.5%

Contributing to our revised earnings guidance for 2018 are the following items:

● We expect 2018 Electric segment net income to be higher than 2017 segment net income based on:

o Normal weather for the remainder of 2018. Milder than normal weather in 2017 negatively impacted diluted earnings per share by an estimated $0.04 compared to normal.

o Constructive outcome of the rate case filed in North Dakota on November 2, 2017, with a full year of increased interim rates in 2018. And constructive outcome of the rate cases filed in South Dakota on April 20, 2018. 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 expect the effects of any reduction in interim or final rates due to lower tax rates in the new tax law to be offset by lower tax expenses. We cannot provide assurance our interim rates will become final.

o Increases in transmission investments and other revenues.

offset by: 

o Increased operating and maintenance expenses of $0.05 per share due to a planned maintenance outage at our Big Stone Plant and $0.09 per share for increasing costs of pension, medical, workers compensation and retiree medical benefits. The increase in pension costs is a result of a decrease in the discount rate from 4.60% to 3.90%.

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

o Increased interest expense related to replacing short-term debt at an average annual rate of 2.4% with long-term debt at a rate of 4.07% along with an increase in combined short-term and long-term borrowings to finance portions of 2018 planned capital expenditures.

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● We expect 2018 net income from our Manufacturing segment to increase over 2017 based on the following:

o An increase in earnings at BTD Manufacturing from an increase in year-over-year sales and planned improvement in operating margins through continued cost reductions.

o An increase in earnings from T.O. Plastics mainly driven by year-over-year sales growth in our horticulture, life science and industrial markets.

o Lower income taxes due to lower federal tax rates implemented as part of the new tax law.

o Backlog for the manufacturing companies of approximately $142 million for 2018 compared with $105 million one year ago.

● While we still expect 2018 net income from the Plastics segment to be lower than 2017, we are revising our earnings guidance for this segment upwards given strong first quarter results. Business conditions in the first quarter saw stronger than expected sales prices resulting in higher operating margins. While announced resin price increases are expected to lower operating margins through the remainder of the year, overall business conditions are expected to remain solid. Earnings in 2017 included an estimated impact of $0.09 per diluted share due to market reaction to hurricanes in the Gulf of Mexico. Plastics segment net income for 2018 will be positively affected by lower federal tax rates in the new tax law.

● Corporate costs, net of tax, are expected to be higher in 2018 than in 2017 when excluding the effect of revaluing deferred tax assets ($0.18 per share) related to tax reform on 2017 net losses. The higher net-of-tax costs expected in 2018 are due, in part, to the lower tax rate in effect in 2018. The change in the guidance range for corporate costs is due to an additional increase in employee benefit costs due to the increase in our overall guidance range.

The impact of 2017 tax reform legislation on future results is based on reasonable estimates and is subject to adjustment on obtaining additional information or to reflect any future legislation, rules, regulations or interpretations of the tax reform legislation. We will continue to analyze and assess the effects of the 2017 tax law changes on our future business projections.

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, interim rate refunds, 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 57 through 59 of our Annual Report on Form 10-K for the year ended December 31, 2017. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2018.

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, 2017, as well as the various factors described below:

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● 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 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 unable 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 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 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 BTD or the Plastics segment 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.

● Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

● Four of our operating companies have single customers that provide a significant portion of the individual operating company’s and the business segment’s revenue. The loss of, or significant reduction in revenue from, any one of these customers would have a significant negative financial impact on the operating company and its business segment and could have a significant negative financial impact on us.

● 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 transmission and generation facilities could be vulnerable to cyber and physical attack that could impair its ability to provide electrical service to its customers or disrupt the U.S. bulk power system.

● 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.

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● 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 PVC 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 affect our plastics business.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At March 31, 2018 we had exposure to market risk associated with interest rates because we had $6.2 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the Otter Tail Corporation Credit Agreement and OTP had $24.1 million in short-term debt outstanding on March 31, 2018 subject to variable interest rates indexed to LIBOR plus 1.25% under the OTP Credit Agreement.

All of our remaining consolidated long-term debt outstanding on March 31, 2018 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 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 March 31, 2018, 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 March 31, 2018.

During the fiscal quarter ended March 31, 2018, 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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are the 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 27 through 33 of our Annual Report on Form 10-K for the year ended December 31, 2017.

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 February 2018 under our 2014 Stock Incentive Plan: 

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
January 2018		--		--
February 2018		58,495	$	41.19
March 2018		--		--
Total		58,495

Item 6.      Exhibits

10.1 Form of 2018 Performance Award Agreement (Executives).*

10.2 Form of 2018 Performance Award Agreement (Legacy).*

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

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

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

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

101 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended March 31, 2018, 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.

*Management contract, compensatory plan or arrangement required to be filed pursuant to Item 601(b)(10)(iii)(A) of Regulation S-K.

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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: May 9, 2017

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EX-10.1

Exhibit 10.1

OTTER TAIL CORPORATION
2014 STOCK INCENTIVE PLAN
2018 EXECUTIVE PERFORMANCE AWARD AGREEMENT

This Performance Award Agreement is between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and you, as an employee of the Corporation, effective as of the date of grant (the “Grant Date”) set forth in the attached Performance Award Certificate.

WHEREAS, the Corporation, pursuant to the Otter Tail Corporation 2014 Stock Incentive Plan (the “Plan”), wishes to grant to you the opportunity and right to receive a number of the Corporation’s Common Shares, par value $5.00 per share (the “Common Shares”), subject to the terms and conditions contained in this Agreement and in the attached Performance Award Certificate, which is made a part of this Agreement.

NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and you hereby agree as follows:

1.     Performance Award. The Corporation hereby grants to you, effective as of the Grant Date, a Performance Award representing the right to receive a specified number of Common Shares, as set forth in the attached Performance Award Certificate and subject to the terms and conditions set forth in this Agreement, the Performance Award Certificate and the Plan. The Performance Award, to the extent it becomes payable, shall be paid in Common Shares of the Corporation (the “Shares”).

2.     Performance Period and Performance Goals. The performance period for purposes of determining whether the Performance Award will be paid shall be January 1, 2018 through December 31, 2020 (the “Performance Period”). The performance goals for purposes of determining whether, and the extent to which, the Performance Award will be paid are set forth in Exhibit 1 to this Agreement, which Exhibit is made a part of this Agreement.

3.     Payment. Subject to the provisions of Sections 4 and 5 of this Agreement, the Performance Award shall be paid within 59 days after the January 15 following the end of the Performance Period after the Compensation Committee of the Corporation’s Board of Directors (the “Committee”) determines, in its discretion, whether and to what extent the performance goals have been achieved in accordance with the terms set forth in Exhibit 1 to this Agreement.

4.     Forfeiture; Early Vesting. Notwithstanding the provisions of Section 3 of this Agreement, in the event your employment is terminated during the Performance Period, the Performance Award and your right to receive any Shares shall be immediately and irrevocably forfeited, unless such termination is by reason of your:

(a)     disability (as determined under any long-term disability program then maintained by the Corporation or any of its Affiliates that is applicable to you);

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(b)     death;

(c)     retirement (voluntary resignation at or after the earlier of (i) age 62 or (ii) your qualifying for normal or early retirement under any retirement plan of the Corporation that is applicable to you); or

(d)     resignation for good reason or involuntary termination without cause that qualifies you for severance benefits under an employment agreement or severance plan applicable to you.

In the event your employment is terminated during the Performance Period for one of the reasons enumerated in clauses (a) or (b) above, then you or your estate shall be entitled to receive a payment of the Performance Award based on, and assuming that, the performance goal would be achieved at the Target level, as set forth in Exhibit 1 to this Agreement. Such payment shall be made as soon as administratively feasible following your separation from service (subject to any required delay under Section 9(a)). If a payment is made pursuant to this paragraph, no payment shall be made pursuant to Section 3 of this Agreement.

In the event you retire during the Performance Period under clause (c) above, then your rights under the Performance Award shall remain outstanding as if you had remained employed for the duration of the Performance Period. You shall be entitled to receive payment of the Performance Award, if any, that becomes payable under Section 3 of this Agreement following the end of the Performance Period, prorated as follows. If you retire on or before June 30 of the calendar year that includes the Grant Date, the Performance Award shall be prorated by multiplying the Performance Award by a fraction, the numerator of which shall be the number of full calendar months during the Performance Period you were so employed, and the denominator of which shall be twelve (12). If you retire after June 30 of the calendar year that includes the Grant Date, any Performance Award that becomes payable under Section 3 shall not be prorated.

In the event your employment is terminated during the Performance Period for one of the reasons enumerated in clause (d) above, then your rights under the Performance Award shall remain outstanding as if you had remained employed for the duration of the Performance Period. You shall be entitled to receive payment of the Performance Award, if any, that becomes payable under Section 3 of this Agreement following the end of the Performance Period, prorated as follows. The Performance Award shall be prorated by multiplying the Performance Award by a fraction, the numerator of which shall be the number of full calendar months during the Performance Period you were so employed, and the denominator of which shall be thirty-six (36).

5.     Change in Control. Notwithstanding the provisions of Section 3 of this Agreement, in the event of a Change in Control (as defined in the Plan) during the Performance Period that occurs prior to your termination of employment, you shall be entitled to receive a payment of the Performance Award based on, and assuming that, the performance goal would have been achieved at the Target level, as set forth in Exhibit 1 to this Agreement. Such payment shall be made promptly following the date of the Change in Control. If a payment is made pursuant to this Section 5, no payment shall be made pursuant to Section 3 of this Agreement. Notwithstanding the foregoing, if any payment due under Section 5 is deferred compensation subject to Section 409A of the Code, and if the Change in Control is not a “change in control event” that serves as a permissible payment event under Treasury Regulation § 1.409A-3(i)(5) or such other regulation or guidance issued under Section 409A of the Code, then the Performance Award shall vest upon the Change in Control as provided above but payment under this Section 5 shall be delayed until the earlier of (i) January 15 following the end of the Performance Period or (ii) the Executive’s separation from service (subject to any additional required delay under Section 9(a)).

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6.     Restriction on Transfer. The Performance Award, and the right to receive Shares, may not be sold, assigned, transferred, pledged, hypothecated or otherwise disposed of or encumbered, other than by will or the laws of descent and distribution, and no attempt to transfer the Performance Award, and the right to receive the Shares, whether voluntary or involuntary, by operation of law or otherwise, shall vest the transferee with any interest or right in or with respect to the Performance Award or the Shares. No transfer by will or the applicable laws of descent and distribution of the Performance Award shall be effective to bind the Corporation unless the Committee shall have been furnished with written notice of such transfer and a copy of the will or such other evidence as the Committee may deem necessary to establish the validity of the transfer.

7.     Issuance of Shares. After the Performance Award becomes payable pursuant to Section 3, 4 or 5 hereof, and following payment of the applicable withholding taxes pursuant to Section 8 hereof, the Corporation shall promptly cause to be issued a certificate or certificates, registered in your name or in the name of your legal representatives, beneficiaries or heirs, as the case may be, representing the Shares (less any shares withheld to pay withholding taxes) and shall cause such certificate or certificates to be delivered to you or your legal representatives, beneficiaries or heirs, as the case may be.

8.     Income Tax Matters.

(a)     You acknowledge that you will consult with your personal tax advisor regarding the income tax consequences of the grant of the Performance Award, the receipt of Shares upon any payment of the Performance Award, the subsequent disposition of the Shares and any other matters related to this Agreement. In order to comply with all applicable federal or state income tax laws or regulations, the Corporation may take such action as it deems appropriate to ensure that all applicable federal or state payroll, withholding, income or other taxes, which are your sole and absolute responsibility, are withheld or collected from you.

(b)     In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, you may elect to satisfy your federal and state income tax withholding obligations arising from the receipt of the Shares by (i) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, (ii) having the Corporation withhold a portion of the Shares otherwise to be delivered having a Fair Market Value equal to the amount of such taxes, provided it does not exceed the employee’s maximum statutory withholding requirements, or (iii) delivering to the Corporation Common Shares having a Fair Market Value equal to the amount of such taxes. The Corporation will not deliver any fractional Share but will pay, in lieu thereof, the Fair Market Value of such fractional Share. Your election must be made on or before the date that the amount of tax to be withheld is determined.

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9.     Miscellaneous.

(a)     Notwithstanding the foregoing, to the extent that any payment due hereunder is (i) deferred compensation subject to Section 409A of the Code (“Section 409A”), and (ii) is payable to a specified employee (as that term is defined in Section 409A), and (iii) is payable on account of the specified employee’s separation from service (as that term is defined in Section 409A), payment of any part of such amount that would have been made during the six (6) months following the separation from service shall not then be paid but shall rather be paid on the first day of the seventh (7th) month following the separation from service.

(i)     For this purpose, specified employees shall be identified by the Corporation on a basis consistent with regulations issued under Section 409A, and consistently applied to all plans, programs, contracts, etc. maintained by the Corporation that are subject to Section 409A.

(ii)     For this purpose “termination of employment” shall be defined as “separation from service” as that term is defined under Section 409A.

(iii)     To the extent that Section 409A is applicable to this Agreement, this Agreement shall be construed and administered to comply with the rules of Section 409A. Neither the Corporation nor any of its officers, directors, agents or affiliates shall be obligated, directly or indirectly, to any participant or any other person for any taxes, penalties, interest or like amounts that may be imposed on the participant or other person on account of any amounts under this Plan or on account of any failure to comply with any Code section.

(b)     Nothing contained in this Agreement or the Plan shall confer on you any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate your employment at any time.

(c)     You shall not have any rights of a holder of Common Shares unless and until Shares are actually issued to you after the end of the Performance Period as provided in this Agreement.

(d)     The Corporation shall not be required to deliver any Shares until the requirements of any federal or state securities laws, rules or regulations or other laws or rules (including the rules of any securities exchange) as may be determined by the Corporation to be applicable are satisfied.

(e)     This Agreement is subject to the terms of the Plan, including, without limitation, the provision for adjustments in Section 4(c) of the Plan. Terms used in this Agreement which are not defined herein shall have the respective meanings given to such terms in the Plan. A copy of the Plan is available to you upon request.

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(f)     This Agreement shall be governed by and construed in accordance with the internal laws of the State of Minnesota, without giving effect to the conflicts of laws principles thereof.

(g)     Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

(h)     THIS PERFORMANCE AWARD AGREEMENT IS ATTACHED TO AND MADE A PART OF A PERFORMANCE AWARD CERTIFICATE AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH PERFORMANCE AWARD CERTIFICATE IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND YOU.

* * * * * * * *

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OTTER TAIL CORPORATION
2014 STOCK INCENTIVE PLAN

PERFORMANCE AWARD CERTIFICATE

This certifies the Performance Award, as specified below, has been granted under the Otter Tail Corporation 2014 Stock Incentive Plan (the “Plan”), the terms and conditions of which are incorporated by reference herein and made a part hereof. In addition, the award shown in this Certificate is nontransferable and is subject to the terms and conditions set forth in the attached 2018 Performance Award Agreement of which this Certificate is a part.

«First» «M» «Last»

«Address»

«City». «State» «Zip»

«SS»  

You have been granted the following Award:

Grant Type:	Performance Award
Target Number of Common Shares Subject to Award:	«Target»
Maximum Number of Common Shares Subject to Award:	«Max»
Grant Date:	February 5, 2018
Performance Period:	January 1, 2018 – December 31, 2020
Performance Goals:	Set forth in Exhibit 1 to the 2018 Executive Performance Award Agreement

By the Corporation’s and your signature below, it is agreed that this Performance Award is governed by the terms and conditions of the Performance Award Agreement, a copy of which is attached and made a part of this document, and the Plan.

OTTER TAIL CORPORATION
By:
	Charles S. MacFarlane Its: President & CEO
«First» «Last»

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Exhibit 1

Performance Goals for Three-Year Performance Period
(January 1, 2018 – December 31, 2020)

			Threshold	Target	Maximum
Performance Goal	Otter Tail TSR performance relative to peer group	<25th %ile	25th %ile	50th %ile	75th %ile or greater
Payment Levels	% of target shares	0%	25%	50%	75%

● Amounts payable for performance will be treated linearly from threshold to target and from target to maximum.

● Total Shareholders Return (TSR) (for both Otter Tail and peer group determination) = stock price appreciation (measured as of the average closing price for the 20 trading days immediately following January 1, 2018 and as of the average closing price for the 20 trading days immediately preceding January 1, 2021), plus value of dividends.

● Peer group = Edison Electric Institute Index as of 12/31/2020.

● Award capped at Target if there is negative TSR.

			Threshold	Target	Maximum
Performance Goal	Adjusted 3-Year ROE	<8.0%	8.25%	9.75%	10.75%
Payment Levels	% of target shares	0%	25%	50%	75%

● Amounts payable for performance will be treated linearly from threshold to target and from target to maximum.

● Adjusted 3-Year Return on Equity (ROE) is equal to the average of Adjusted Return on Equity for each of the three years in the Performance Period.

● Adjusted Return on Equity is equal to the Corporation’s Adjusted Earnings divided by the 13-month average of Total Outstanding Common Equity using the 13 months ending at the end of the fiscal year.

● Adjusted Earnings is equal to the earnings available for Common Shares as reported in the Corporation’s annual year-end financial report, as adjusted to reflect (1) unusual, extraordinary or nonrecurring events; (2) changes in applicable accounting rules or principles or in the Company’s methods of accounting; (3) results of discontinued operations; (4) asset write-downs; (5) litigation or claim judgments or settlements; (6) changes in tax law affecting reported results; (7) severance, contract termination and other costs related to exiting business activities; (8) acquisitions; (9) gains or losses from the disposition of businesses or assets; (10) gains or losses from the early extinguishment of debt; and (11) other publicly identified one-time items (collectively, the “Adjustment Items”).

● Total Outstanding Common Equity is equal to the month end common equity balance.

● The Committee may exercise discretion to not make adjustment for one or more Adjustment Items when determining Adjusted Earnings.

The number of Common Shares payable is determined by taking the sum of the percentages earned in each of the tables.

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EX-10.2

Exhibit 10.2

OTTER TAIL CORPORATION
2014 STOCK INCENTIVE PLAN
2018 LEGACY PERFORMANCE AWARD AGREEMENT

This Performance Award Agreement is between Otter Tail Corporation, a Minnesota corporation (the “Corporation”), and you, as an employee of the Corporation, effective as of the date of grant (the “Grant Date”) set forth in the attached Performance Award Certificate.

WHEREAS, the Corporation, pursuant to the Otter Tail Corporation 2014 Stock Incentive Plan (the “Plan”), wishes to grant to you the opportunity and right to receive a number of the Corporation’s Common Shares, par value $5.00 per share (the “Common Shares”), subject to the terms and conditions contained in this Agreement and in the attached Performance Award Certificate, which is made a part of this Agreement.

NOW, THEREFORE, for good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Corporation and you hereby agree as follows:

1.     Performance Award. The Corporation hereby grants to you, effective as of the Grant Date, a Performance Award representing the right to receive a specified number of Common Shares, as set forth in the attached Performance Award Certificate and subject to the terms and conditions set forth in this Agreement, the Performance Award Certificate and the Plan. The Performance Award, to the extent it becomes payable, shall be paid in Common Shares of the Corporation (the “Shares”).

2.     Performance Period and Performance Goals. The performance period for purposes of determining whether the Performance Award will be paid shall be January 1, 2018 through December 31, 2020 (the “Performance Period”). The performance goals for purposes of determining whether, and the extent to which, the Performance Award will be paid are set forth in Exhibit 1 to this Agreement, which Exhibit is made a part of this Agreement.

3.     Payment. Subject to the provisions of Sections 4 and 5 of this Agreement, the Performance Award shall be paid within 59 days after the January 15 following the end of the Performance Period after the Compensation Committee of the Corporation’s Board of Directors (the “Committee”) determines, in its discretion, whether and to what extent the performance goals have been achieved in accordance with the terms set forth in Exhibit 1 to this Agreement.

4.     Forfeiture; Early Vesting. Notwithstanding the provisions of Section 3 of this Agreement, in the event your employment is terminated during the Performance Period, the Performance Award and your right to receive any Shares shall be immediately and irrevocably forfeited, unless such termination is by reason of your:

(a)     disability (as determined under any long-term disability program then maintained by the Corporation or any of its Affiliates that is applicable to you);

(b)     death;

1

(c)     retirement (normal or early retirement under any retirement plan of the Corporation or any of its Affiliates that is applicable to you), provided you are at least 62 years old at the time of such retirement;

(d)     resignation for “Good Reason” (as defined in your Executive Employment Agreement, dated on or before the Grant Date, between the Corporation and you); or

(e)     termination “Without Cause” (as defined in your Executive Employment Agreement, dated on or before the Grant Date, between the Corporation and you)).

In the event your employment is terminated during the Performance Period for one of the reasons enumerated in clauses (a) through (c) above, then you or your estate shall be entitled to receive a payment of the Performance Award based on, and assuming that, the performance goal would be achieved at the Target level, as set forth in Exhibit 1 to this Agreement. Such payment shall be made as soon as administratively feasible following your separation from service (subject to any required delay under Section 9(a)). In the event your employment is terminated during the Performance Period for one of the reasons enumerated in clause (d) or (e) above or retirement before age 62, then you shall be entitled to receive a pro rata payment of the Performance Award based on the performance of the Company against the performance goal as of the date of such termination, as set forth in Exhibit 1 to this Agreement (subject to any required delay under Section 9(a)). If a payment is made pursuant to this Section 4, no payment shall be made pursuant to Section 3 of this Agreement.

5.     Change in Control. Notwithstanding the provisions of Section 3 of this Agreement, in the event of a Change in Control (as defined in the Plan) during the Performance Period that occurs prior to your termination of employment, you shall be entitled to receive a payment of the Performance Award based on, and assuming that, the performance goal would have been achieved at the Target level, as set forth in Exhibit 1 to this Agreement. Such payment shall be made promptly following the date of the Change in Control. If a payment is made pursuant to this Section 5, no payment shall be made pursuant to Section 3 of this Agreement. Notwithstanding the foregoing, if any payment due under Section 5 is deferred compensation subject to Section 409A of the Code, and if the Change in Control is not a “change in control event” that serves as a permissible payment event under Treasury Regulation § 1.409A-3(i)(5) or such other regulation or guidance issued under Section 409A of the Code, then the Performance Award shall vest upon the Change in Control as provided above but payment under this Section 5 shall be delayed until the earlier of (i) January 15 following the end of the Performance Period or (ii) the Executive’s separation from service (subject to any additional required delay under Section 9(a)).

6.     Restriction on Transfer. The Performance Award, and the right to receive Shares, may not be sold, assigned, transferred, pledged, hypothecated or otherwise disposed of or encumbered, other than by will or the laws of descent and distribution, and no attempt to transfer the Performance Award, and the right to receive the Shares, whether voluntary or involuntary, by operation of law or otherwise, shall vest the transferee with any interest or right in or with respect to the Performance Award or the Shares. No transfer by will or the applicable laws of descent and distribution of the Performance Award shall be effective to bind the Corporation unless the Committee shall have been furnished with written notice of such transfer and a copy of the will or such other evidence as the Committee may deem necessary to establish the validity of the transfer.

2

7.     Issuance of Shares. After the Performance Award becomes payable pursuant to Section 3, 4 or 5 hereof, and following payment of the applicable withholding taxes pursuant to Section 8 hereof, the Corporation shall promptly cause to be issued a certificate or certificates, registered in your name or in the name of your legal representatives, beneficiaries or heirs, as the case may be, representing the Shares (less any shares withheld to pay withholding taxes) and shall cause such certificate or certificates to be delivered to you or your legal representatives, beneficiaries or heirs, as the case may be.

8.     Income Tax Matters.

(a)     You acknowledge that you will consult with your personal tax advisor regarding the income tax consequences of the grant of the Performance Award, the receipt of Shares upon any payment of the Performance Award, the subsequent disposition of the Shares and any other matters related to this Agreement. In order to comply with all applicable federal or state income tax laws or regulations, the Corporation may take such action as it deems appropriate to ensure that all applicable federal or state payroll, withholding, income or other taxes, which are your sole and absolute responsibility, are withheld or collected from you.

(b)     In accordance with the terms of the Plan, and such rules as may be adopted by the Committee under the Plan, you may elect to satisfy your federal and state income tax withholding obligations arising from the receipt of the Shares by (i) delivering cash, check (bank check, certified check or personal check) or money order payable to the order of the Corporation, (ii) having the Corporation withhold a portion of the Shares otherwise to be delivered having a Fair Market Value equal to the amount of such taxes, provided it does not exceed the employee’s maximum statutory withholding requirements or (iii) delivering to the Corporation Common Shares having a Fair Market Value equal to the amount of such taxes. The Corporation will not deliver any fractional Share but will pay, in lieu thereof, the Fair Market Value of such fractional Share. Your election must be made on or before the date that the amount of tax to be withheld is determined.

9.     Miscellaneous.

(a)     Notwithstanding the foregoing, to the extent that any payment due hereunder is (i) deferred compensation subject to Section 409A of the Code (“Section 409A”), and (ii) is payable to a specified employee (as that term is defined in Section 409A), and (iii) is payable on account of the specified employee’s separation from service (as that term is defined in Section 409A), payment of any part of such amount that would have been made during the six (6) months following the separation from service shall not then be paid but shall rather be paid on the first day of the seventh (7th) month following the separation from service.

(i)     For this purpose, specified employees shall be identified by the Corporation on a basis consistent with regulations issued under Section 409A, and consistently applied to all plans, programs, contracts, etc. maintained by the Corporation that are subject to Section 409A.

3

(ii)     For this purpose “termination of employment” shall be defined as “separation from service” as that term is defined under Section 409A.

(iii)     To the extent that Section 409A is applicable to this Agreement, this Agreement shall be construed and administered to comply with the rules of Section 409A. Neither the Corporation nor any of its officers, directors, agents or affiliates shall be obligated, directly or indirectly, to any participant or any other person for any taxes, penalties, interest or like amounts that may be imposed on the participant or other person on account of any amounts under this Plan or on account of any failure to comply with any Code section.

(b)     Nothing contained in this Agreement or the Plan shall confer on you any right to continue in the employ of the Corporation or any Affiliate or affect in any way the right of the Corporation or any Affiliate to terminate your employment at any time.

(c)     You shall not have any rights of a holder of Common Shares unless and until Shares are actually issued to you after the end of the Performance Period as provided in this Agreement.

(d)     The Corporation shall not be required to deliver any Shares until the requirements of any federal or state securities laws, rules or regulations or other laws or rules (including the rules of any securities exchange) as may be determined by the Corporation to be applicable are satisfied.

(e)     This Agreement is subject to the terms of the Plan, including, without limitation, the provision for adjustments in Section 4(c) of the Plan. Terms used in this Agreement which are not defined herein shall have the respective meanings given to such terms in the Plan. A copy of the Plan is available to you upon request.

(f)     This Agreement shall be governed by and construed in accordance with the internal laws of the State of Minnesota, without giving effect to the conflicts of laws principles thereof.

(g)     Headings in this Agreement are for convenience of reference only and shall not be deemed in any way to be material or relevant to the construction or interpretation of this Agreement or any provision hereof.

(h)     THIS PERFORMANCE AWARD AGREEMENT IS ATTACHED TO AND MADE A PART OF A PERFORMANCE AWARD CERTIFICATE AND SHALL HAVE NO FORCE OR EFFECT UNLESS SUCH PERFORMANCE AWARD CERTIFICATE IS DULY EXECUTED AND DELIVERED BY THE CORPORATION AND YOU.

* * * * * * * *

4

OTTER TAIL CORPORATION
2014 STOCK INCENTIVE PLAN

PERFORMANCE AWARD CERTIFICATE

This certifies the Performance Award, as specified below, has been granted under the Otter Tail Corporation 2014 Stock Incentive Plan (the “Plan”), the terms and conditions of which are incorporated by reference herein and made a part hereof. In addition, the award shown in this Certificate is nontransferable and is subject to the terms and conditions set forth in the attached 2018 Legacy Performance Award Agreement of which this Certificate is a part.

«First» «M» «Last»

«Address»

«City», «State»  «Zip»

«SS»

You have been granted the following Award:

Grant Type:	Performance Award
Target Number of Common Shares Subject to Award:	«Target»
Maximum Number of Common Shares Subject to Award:	«Max»
Grant Date:	February 5, 2018
Performance Period:	January 1, 2018 – December 31, 2020
Performance Goals:	Set forth in Exhibit 1 to the 2018 Legacy Performance Award Agreement

By the Corporation’s and your signature below, it is agreed that this Performance Award is governed by the terms and conditions of the Legacy Performance Award Agreement, a copy of which is attached and made a part of this document, and the Plan.

OTTER TAIL CORPORATION
By:
	Charles S. MacFarlane Its: President & CEO
«First» «Last»

5

Exhibit 1

Performance Goals for Three-Year Performance Period
(January 1, 2018 – December 31, 2020)

			Threshold	Target	Maximum
Performance Goal	Otter Tail TSR performance relative to peer group	<25th %ile	25th %ile	50th %ile	75th %ile or greater
Payment Levels	% of target shares	0%	25%	50%	75%

● Amounts payable for performance will be treated linearly from threshold to target and from target to maximum.

● Total Shareholders Return (TSR) (for both Otter Tail and peer group determination) = stock price appreciation (measured as of the average closing price for the 20 trading days immediately following January 1, 2018 and as of the average closing price for the 20 trading days immediately preceding January 1, 2021), plus value of dividends.

● Peer group = Edison Electric Institute Index as of 12/31/2020.

● Award capped at Target if there is negative TSR.

			Threshold	Target	Maximum
Performance Goal	Adjusted 3-Year ROE	<8.0%	8.25%	9.75%	10.75%
Payment Levels	% of target shares	0%	25%	50%	75%

● Amounts payable for performance will be treated linearly from threshold to target and from target to maximum.

● Adjusted 3-Year Return on Equity (ROE) is equal to the average of Adjusted Return on Equity for each of the three years in the Performance Period.

● Adjusted Return on Equity is equal to the Corporation’s Adjusted Earnings divided by the 13-month average of Total Outstanding Common Equity using the 13 months ending at the end of the fiscal year.

● Adjusted Earnings is equal to the earnings available for Common Shares as reported in the Corporation’s annual year-end financial report, as adjusted to reflect (1) unusual, extraordinary or nonrecurring events; (2) changes in applicable accounting rules or principles or in the Company’s methods of accounting; (3) results of discontinued operations; (4) asset write-downs; (5) litigation or claim judgments or settlements; (6) changes in tax law affecting reported results; (7) severance, contract termination and other costs related to exiting business activities; (8) acquisitions; (9) gains or losses from the disposition of businesses or assets; (10) gains or losses from the early extinguishment of debt; and (11) other publicly identified one-time items (collectively, the “Adjustment Items”).

● Total Outstanding Common Equity is equal to the month end common equity balance.

● The Committee may exercise discretion to not make adjustment for one or more Adjustment Items when determining Adjusted Earnings.

The number of Common Shares payable is determined by taking the sum of the percentages earned in each of the tables.

6

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles S. MacFarlane, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 9, 2018

/s/ Charles S. MacFarlane
Charles S. MacFarlane

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Moug, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: May 9, 2018

/s/ Kevin G. Moug
Kevin G. Moug

Chief Financial Officer and Senior Vice President

EX-32.1

Exhibit 32.1 

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles S. MacFarlane, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Charles S. MacFarlane                                      

Charles S. MacFarlane

President and Chief Executive Officer 

May 9, 2018

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Kevin G. Moug                                                     

Kevin G. Moug

Chief Financial Officer and Senior Vice President 

May 9, 2018

XML

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
Document Information [Line Items]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	0001466593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding (in shares)		39,651,236
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Amendment Flag	false

XML

Consolidated Balance Sheets (Current Period Not Audited) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 1,121	$ 16,216
Accounts Receivable:
Trade—Net	94,265	68,466
Other	7,109	7,761
Inventories	87,999	88,034
Unbilled Receivables	18,692	22,427
Income Taxes Receivable		1,181
Regulatory Assets	19,736	22,551
Other	11,210	12,491
Total Current Assets	240,132	239,127
Investments	8,648	8,629
Other Assets	35,763	36,006
Goodwill	37,572	37,572
Other Intangibles—Net	13,420	13,765
Regulatory Assets	125,667	129,576
Plant
Electric Plant in Service	1,986,385	1,981,018
Nonelectric Operations	219,942	216,937
Construction Work in Progress	153,963	141,067
Total Gross Plant	2,360,290	2,339,022
Less Accumulated Depreciation and Amortization	814,074	799,419
Net Plant	1,546,216	1,539,603
Total Assets	2,007,418	2,004,278
Current Liabilities
Short-Term Debt	30,319	112,371
Current Maturities of Long-Term Debt	171	186
Accounts Payable	87,179	84,185
Accrued Salaries and Wages	14,806	21,534
Accrued Federal and State Income Taxes	984
Accrued Taxes	17,585	16,808
Regulatory Liabilities	5,119	9,688
Other Accrued Liabilities	9,940	11,389
Liabilities of Discontinued Operations		492
Total Current Liabilities	166,103	256,653
Pensions Benefit Liability	89,552	109,708
Other Postretirement Benefits Liability	70,040	69,774
Other Noncurrent Liabilities	23,482	22,769
Commitments and Contingencies (note 8)
Deferred Credits
Deferred Income Taxes	103,009	100,501
Deferred Tax Credits	21,025	21,379
Regulatory Liabilities - Long -Term	233,279	232,893
Other	2,935	3,329
Total Deferred Credits	360,248	358,102
Capitalization
Long-Term Debt—Net	589,943	490,380
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2018—39,626,594 Shares; 2017—39,557,491 Shares	198,133	197,787
Premium on Common Shares	341,841	343,450
Retained Earnings	174,209	161,286
Accumulated Other Comprehensive Loss	(6,133)	(5,631)
Total Common Equity	708,050	696,892
Total Capitalization	1,297,993	1,187,272
Total Liabilities and Equity	2,007,418	2,004,278
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares

XML

Consolidated Balance Sheets (Current Period Not Audited) (Parentheticals) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized (in shares)	50,000,000	50,000,000
Common shares, outstanding (in shares)	39,626,594	39,557,491
Cumulative Preferred Shares [Member]
Cumulative shares, authorized (in shares)	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0
Cumulative Preference Shares [Member]
Cumulative shares, authorized (in shares)	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0

XML

Consolidated Statements of Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues:
Operating Revenues	$ 241,266	$ 214,117
Operating Expenses
Production Fuel – Electric	18,706	16,382
Cost of Products Sold (depreciation included below)	88,785	75,277
Electric Operation and Maintenance Expenses	39,475	37,277
Other Nonelectric Expenses	12,494	10,135
Depreciation and Amortization	18,763	17,854
Property Taxes – Electric	3,835	3,798
Total Operating Expenses	203,651	179,911
Operating Income	37,615	34,206
Interest Charges	7,372	7,462
Nonservice Cost Components of Postretirement Benefits	1,417	1,405
Other Income	1,183	553
Income Before Income Taxes – Continuing Operations	30,009	25,892
Income Tax Expense – Continuing Operations	3,794	6,363
Net Income from Continuing Operations	26,215	19,529
Income from Discontinued Operations – net of Income Tax Expense of $38 in 2017		56
Net Income	$ 26,215	$ 19,585
Average Number of Common Shares Outstanding—Basic (in shares)	39,550,874	39,350,802
Average Number of Common Shares Outstanding—Diluted (in shares)	39,863,682	39,640,725
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 0.66	$ 0.50
Discontinued Operations (in dollars per share)
(in dollars per share)	0.66	0.50
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	0.66	0.49
Discontinued Operations (in dollars per share)
(in dollars per share)	0.66	0.49
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 123,825	$ 119,782
Changes in Accrued Revenues under Alternative Revenue Programs	(875)	(1,239)
Operating Revenues	122,950	118,543
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	118,316	95,574
Electricity, Purchased [Member]
Operating Expenses
Cost of Products Sold (depreciation included below)	$ 21,593	$ 19,188

XML

Consolidated Statements of Income (Not Audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Tax Expense - Discontinued Operations		$ 38

XML

Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net Income	$ 26,215	$ 19,585
Unrealized Gains on Available-for-Sale Securities:
Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period	(110)
Unrealized (Losses) Gains Arising During Period	(66)	17
Income Tax Benefit (Expense)	37	(6)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax	(139)	11
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10)	227	157
Income Tax Expense	(59)	(63)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act	(531)
Pension and Postretirement Benefit Plans – net-of-tax	(363)	94
Total Other Comprehensive (Loss) Income	(502)	105
Total Comprehensive Income	$ 25,713	$ 19,690

XML

Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities
Net Income	$ 26,215	$ 19,585
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		(56)
Depreciation and Amortization	18,763	17,854
Deferred Tax Credits	(354)	(366)
Deferred Income Taxes	2,901	4,512
Change in Deferred Debits and Other Assets	6,295	5,005
Discretionary Contribution to Pension Plan	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	(5,091)	1,314
Allowance for Equity/Other Funds Used During Construction	(638)	(170)
Stock Compensation Expense—Equity Awards	1,146	1,150
Other—Net	(284)	(5)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(25,047)	(15,521)
Change in Inventories	35	2,267
Change in Other Current Assets	2,334	(22)
Change in Payables and Other Current Liabilities	(2,598)	(13,986)
Change in Interest and Income Taxes Receivable/Payable	1,163	(321)
Net Cash Provided by Continuing Operations	4,840	21,240
Net Cash Used in Discontinued Operations	(200)	(39)
Net Cash Provided by Operating Activities	4,640	21,201
Cash Flows from Investing Activities
Capital Expenditures	(23,618)	(30,113)
Net Proceeds from Disposal of Noncurrent Assets	510	612
Cash Used for Investments and Other Assets	(719)	(508)
Net Cash Used in Investing Activities	(23,827)	(30,009)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	2,338	7,999
Net Short-Term (Repayments) Borrowings	(82,052)	16,293
Proceeds from Issuance of Common Stock – net of Issuance Expenses		1,958
Payments for Retirement of Capital Stock	(2,409)	(1,759)
Proceeds from Issuance of Long-Term Debt	100,000
Short-Term and Long-Term Debt Issuance Expenses	(433)
Payments for Retirement of Long-Term Debt	(60)	(3,057)
Dividends Paid	(13,292)	(12,626)
Net Cash Provided by Financing Activities	4,092	8,808
Net Change in Cash and Cash Equivalents	(15,095)
Cash and Cash Equivalents at Beginning of Period	16,216
Cash and Cash Equivalents at End of Period	$ 1,121

XML

Note 1 - Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Significant Accounting Policies and New Accounting Pronouncements [Text Block]

1.

Summary of Significant Accounting Policies

Revenue Recognition

In

May 2014

the Financial Accounting Standards Board (FASB) issued a major update to the Accounting Standards Codification (ASC), Accounting Standards Update (ASU)

No.

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

(ASC

606

). The Company adopted the updates in ASC

606

effective

January 1, 2018

on a modified retrospective basis but did

not

record a cumulative effect adjustment to retained earnings on application of the updates because the adoption of the updates in ASC

606

had

no

material impact on the timing of revenue recognition for the Company or its subsidiaries. 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.

Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has

not

identified any contracts where the timing of revenue recognition will change as a result of the adoption of the updates in ASC

606.

Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.

In addition to recognizing revenue from contracts with customers under ASC

606,

the Company also records adjustments to Electric segment revenues for amounts subject to future collection or refund under alternative revenue programs (ARPs) as defined in ASC Topic

980,

Regulated Operations

(ASC

980

). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do

not

meet the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues

—In the Electric segment, the Company recognizes revenue in

two

categories: (

1

) revenues from contracts with customers and (

2

) adjustments to revenues for amounts collectible or refundable under ARPs.

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A

third

source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning incentives or returns on investments subject to recovery under several ARP rate riders, including:

● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders.

● In North Dakota: TCR, ECR and RRA riders

● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders.

OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note

3

for total revenues billed and accrued under ARP riders for the

three

-month periods ended

March 31, 2018

and

2017.

Manufacturing

Segment Revenues

—Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped and adjusts the revenue for volume rebate variable pricing considerations the company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on products when shipped, the operating companies have

no

further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Plastics Segment Revenues

—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl-chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. Billed amounts of revenue recognized are adjusted for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on shipped products, there is

no

further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. The Plastics segment has

one

customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is also recognized over time as the pipe is stored.

See operating revenue table in note

2

to consolidated financial statements for a disaggregation of the Company’s revenues by business segment for the

three

-month periods ended

March 31, 2018

and

2017.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according 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 hierarchical 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.

Level

2

– Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level

2

are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level

3

– Significant inputs to pricing have little or

no

observability as of the reporting date. The types of assets and liabilities included in Level

3

are those with inputs requiring significant management judgment or estimation and

may

include complex and subjective models and forecasts.

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of

March 31, 2018

and

December 31, 2017:

March 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,220
Corporate Debt Securities – Held by Captive Insurance Company			$	5,341
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,779
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		870
Total Assets	$	2,090	$	7,120

December 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,285
Corporate Debt Securities – Held by Captive Insurance Company			$	5,373
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,787
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		823
Total Assets	$	2,108	$	7,160

The valuation techniques and inputs used for the Level

2

fair value measurements in the table above are as follows:

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.

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 paid by the Coyote Station owners under the LSA reflects 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.

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. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of

March 31, 2018

could be as high as

$56.5

 million, OTP’s

35%

share of unrecovered costs.

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

	March 31,		December 31,
(in thousands)	2018		2017
Finished Goods	$	25,341	$	26,605
Work in Process		17,224		14,222
Raw Material, Fuel and Supplies		45,434		47,207
Total Inventories	$	87,999	$	88,034

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of

December 31, 2017

indicated the fair values are substantially in excess of their respective book values and

not

impaired.

The following table indicates there were

no

changes to goodwill by business segment during the

first

three

months of

2018:

(in thousands)	Gross Balance December 31, 2017		Accumulated Impairments		Balance (net of impairments) December 31, 2017		Adjustments to Goodwill in 2018		Balance (net of impairments) March 31, 2018
Manufacturing	$	18,270	$	--	$	18,270	$	--	$	18,270
Plastics		19,302		--		19,302		--		19,302
Total	$	37,572	$	--	$	37,572	$	--	$	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

March 31, 2018

and

December 

31,

 

2017:

March 31 , 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	9,277	$	13,214	21	-	209
Covenant not to Compete		590		508		82		5
Other		154		30		124		29
Total	$	23,235	$	9,815	$	13,420

December 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,994	$	13,497	24	-	212
Covenant not to Compete		590		459		131		8
Other		154		17		137		32
Total	$	23,235	$	9,470	$	13,765

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Amortization Expense – Intangible Assets	$	345	$	332

The estimated annual amortization expense for these intangible assets for the next

five

years is:

(in thousands)	2018		2019		2020		2021		2022
Estimated Amortization Expense – Intangible Assets	$	1,315	$	1,184	$	1,133	$	1,099	$	1,099

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2018		2017
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,451	$	10,811

New Accounting Standards Adopted

ASU

2014

-

09

—In

May 2014

the FASB issued ASU

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

.

The Company adopted the updates in ASC

606

effective

January 1, 2018

on a modified retrospective basis. See disclosures above under Revenue Recognition.

ASU

2016

-

01

—In

January 2016

the FASB issued ASU

No.

2016

-

01,

Financial Instruments—Overall

(Subtopic

825

-

10

)

(ASU

2016

-

01

). The amendments in ASU

2016

-

01

address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments and require equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. For the Company, the amendments in ASU

2016

-

01are

effective for fiscal years beginning after

December 15, 2017,

including interim periods within those fiscal years. The Company adopted the updates in ASU

2016

-

01

in the

first

quarter of

2018,

which resulted in changes in the fair value of equity instruments held as investments by the Company’s captive insurance company being classified in net income. The fair value of equity instruments held by the Company’s captive insurance company on

March 31, 2018

were

$1,220,000

and the amount of unrealized gains on those investments recorded in net income in the

first

quarter of

2018

was

$87,000.

ASU

2017

-

07

—In

March 2017

the FASB issued ASU

No.

2017

-

07,

Compensation—Retirement Benefits (Topic

715

): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

(ASU

2017

-

07

), with the intent of improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic

715,

Compensation—Retirement Benefits

(ASC

715

)

,

does

not

prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does

not

require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets. The amendments in ASU

2017

-

07

require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period, which the Company has provided in the electric operation and maintenance and other nonelectric expense lines on its income statement. The other components of net benefit cost as defined in ASC

715

are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has provided the amount of the non-service cost components of net periodic postretirement benefit costs in a separate line below interest expense on the face of its consolidated income statement. The amendments in ASU

2017

-

07

also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU

2017

-

07

are effective for annual periods beginning after

December 15, 2017,

including interim periods within those annual periods. The amendments have been applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the Company’s consolidated income statements and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit cost in assets.

The majority of the Company’s benefit costs to which the amendments in ASU

2017

-

07

apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU

2017

-

07

deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs applicable to OTP, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all the components of net periodic pension costs as recoverable operating expenses. The Company has assessed the impact adoption of the amendments in ASU

2017

-

07

will have on its consolidated financial statements, financial position and results of operations and OTP has established regulatory assets to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under ASU

2017

-

07.

The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in

2017

that would have been recorded as regulatory assets if the amendments in ASU

2017

-

07

were applicable in

2017

were

$0.8

million. The Company’s non-service costs components of net periodic postretirement benefit costs included in operating expense in

2017

and

2016

that will be reported in other income and deductions in the Company's

2018

 annual report on Form

10

-K after adoption of ASU

2017

-

07

were

$5.6

million for

2017

and

$5.1

million for

2016.

Additional information on the allocation of postretirement benefit costs for the

three

-month periods ended

March 31, 2018

and

2017

is provided in note

10

to these consolidated financial statements for the Company’s major benefit programs presented.

New Accounting Standards Pending Adoption

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 Generally Accepted Accounting Principles in the United States (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 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 has developed a list of all current leases outstanding and continues to review ASU

2016

-

02,

identifying key impacts to its businesses to determine areas where the amendments in ASU

2016

-

02

will be applicable and is 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

2017

-

04

—In

January 2017

the FASB issued ASU

No.

2017

-

04,

Intangibles—Goodwill and Other (Topic

350

): Simplifying the Test for Goodwill Impairment

(ASU

2017

-

04

), which simplifies how an entity is required to test goodwill for impairment by eliminating Step

2

from the goodwill impairment test. Step

2

measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step

2,

an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU

2017

-

04,

an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will

not

exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in ASU

2017

-

04

modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity

no

longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step

2

from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU

2017

-

04

are effective for annual or any interim goodwill impairment tests in fiscal years beginning after

December 15, 2019.

Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after

January 1, 2017.

ASU

201

8

-

0

2

—In

February 2018

the FASB issued ASU

No.

2018

-

02,

Income Statement—Reporting Comprehensive Income (Topic

220

):

Reclassification of Certain Tax Effects from

Accumulated Other Comprehensive Income

(ASU

2018

-

02

). The amendments in ASU

2018

-

02,

which are narrow in scope, allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the

2017

Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users. The amendments in ASU

2018

-

02

also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after

December 15, 2018,

and interim periods within those fiscal years. Early adoption of the amendments in ASU

2018

-

02

is permitted. The amendments in ASU

2018

-

02

can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company does

not

plan to adopt the amendments in ASU

2018

-

02

until the

first

quarter of

2019.

On adoption, the Company will reclassify the

$784,000

of income tax effects of the TCJA on the gross deferred tax amounts at the date of enactment of the TCJA related to items remaining in accumulated other comprehensive income from other comprehensive income to retained earnings so that the remaining gross deferred tax amounts related to items in other comprehensive income will reflect current effective tax rates.

XML

Note 2 - Segment Information

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Segment Reporting Disclosure [Text Block]

2.

Segment Information

Segment Information

The accounting policies of the segments are described under note

1

– Summary of Significant Accounting Policies. 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 Company’s business structure currently includes the following

three

segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is 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 plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.

Plastics consists of businesses producing 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

2017.

The Electric segment has

one

customer that provided

11.7%

of

2017

Electric segment revenues. The Manufacturing segment has

one

customer that manufactures and sells recreational vehicles that provided

24.3%

of

2017

Manufacturing segment revenues and

one

customer that manufactures and sells lawn and garden equipment that provided

12.0%

of

2017

Manufacturing segment revenues. The Plastics segment has

two

customers that individually provided

20.6%

and

17.8%

of

2017

Plastics segment revenues. The loss of any

one

of these customers would have a significant negative impact on the financial position and results of operations of the respective business segment and the Company.

All of the Company’s long-lived assets are within the United States and

98.3%

and

98.4%

of its operating revenues for the respective

three

-month periods ended

March 31, 2018

and

2017

came from sales within the United States.

The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the

three

months ended

March 

31,

2018

and

2017

and total assets by business segment as of

March 31, 2018

and

December 

31,

2017

are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	109,180		$	106,454
Changes in Accrued ARP Revenues		(875	)		(1,239	)
Total Retail Sales Revenue		108,305			105,215
Wholesale Revenues – Company Generation		1,015			867
Other Revenues		13,645			12,469
Total Electric Segment Revenues	$	122,965		$	118,551
Manufacturing Segment:
Metal Parts and Tooling	$	56,927		$	48,078
Plastic Products		10,235			9,552
Other		1,500			787
Total Manufacturing Segment Revenues	$	68,662		$	58,417
Plastics Segment – Sale of PVC Pipe Products	$	49,653		$	37,157
Intersegment Eliminations	$	(14	)	$	(8	)
Total	$	241,266		$	214,117

Interest

Charges

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Electric	$	6,390	$	6,386
Manufacturing		554		554
Plastics		150		153
Corporate and Intersegment Eliminations		278		369
Total	$	7,372	$	7,462

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	2,098		$	6,062
Manufacturing		1,223			1,055
Plastics		2,414			1,390
Corporate		(1,941	)		(2,144	)
Total	$	3,794		$	6,363

Net Income

(Loss)

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	16,668		$	15,560
Manufacturing		4,164			2,172
Plastics		6,844			2,437
Corporate		(1,461	)		(640	)
Discontinued Operations		--			56
Total	$	26,215		$	19,585

Identifiable

Assets

	March 31,		December 31,
(in thousands)	2018		2017
Electric	$	1,686,255	$	1,690,224
Manufacturing		180,319		167,023
Plastics		97,953		87,230
Corporate		42,891		59,801
Total	$	2,007,418	$	2,004,278

XML

Note 3 - Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Public Utilities Disclosure [Text Block]

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 FERC, impacting OTP’s revenues in

2018

and

2017.

Major Capital Expenditure Projects

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)

—This is a

345

-kiloVolt (kV) transmission line that will extend

163

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., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in

December 2011.

MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the

second

quarter of

2016

and is expected to be completed in

2019.

OTP’s capitalized costs on this project as of

March 31, 2018

were approximately

$96.5

 million, which includes assets that are

100%

owned by OTP.

Big Stone South–Brookings MVP

—This

345

-kV transmission line extends 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–Minnesota, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties 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 was energized on

September 8, 2017.

OTP’s capitalized costs on this project as of

March 31, 2018

were approximately

$72.4

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

General Rate

s

—The MPUC rendered its final decision in OTP’s

2016

general rate case in

March 2017

and issued its written order on

May 1, 2017.

Pursuant to the order, OTP’s allowed rate of return on rate base decreased from

8.61%

to

7.5056%

and its allowed rate of return on equity decreased from

10.74%

to

9.41%.

The MPUC’s order also included: (

1

) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVPs will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (

2

) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of

$9.0

million was applied as a credit to Minnesota customers’ electric bills beginning

November 17, 2017.

In addition to the interim rate refund, OTP will refund the difference between (

1

) amounts collected under its Minnesota ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (

2

) amounts that would have been collected based on the lower

9.41%

ROE approved in its

2016

general rate case going back to

April 16, 2016,

the date interim rates were implemented. As of

October 31, 2017,

the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were

$0.9

million and

$1.4

 million, respectively. These amounts are being refunded to Minnesota customers over a

12

-month period through reductions in the Minnesota ECR and TCR rider rates in effect

November 1, 2017,

as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

Minnesota Conservation Improvement Programs

(MNCIP)

—OTP recovers conservation related costs

not

included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On

May 25, 2016

the MPUC adopted the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The model provides 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. The financial incentive is also limited to

40%

of

2017

MNCIP spending,

35%

of

2018

spending and

30%

of

2019

spending.

Based on results from the

2017

MNCIP program year, OTP recognized a financial incentive of

$2.6

million in

2017.

The

2017

program resulted in an approximate

10%

decrease in energy savings compared to

2016

program results. OTP requested approval for recovery of its

2017

MNCIP program costs

not

included in base rates, a

$2.6

million financial incentive and an update to the MNCIP surcharge from the MPUC on

March 31, 2018.

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 of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC

may

approve annual rate adjustments filed pursuant to the rate schedule.

In OTP’s

2016

general rate case order issued on

May 1, 2017,

the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverts interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on the differences between the revenue requirements and returns in the

two

jurisdictions at any given time. On

August 18, 2017

OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider. On

March 22, 2018

oral arguments were made before the Minnesota Court of Appeals. A decision is anticipated by the end of the

second

quarter

2018.

OTP believes the MPUC-ordered treatment conflicts with federal authority over interstate transmission of electricity in and with FERC electric transmission rates as set forth in the Federal Power Act of

1935,

as amended (Federal Power Act).

Environmental Cost Recovery Rider

— OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s

2010

general rate case. In its

2016

general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, effective with implementation of final rates in

November 2017.

Renewable Resource Adjustment

— Effective

November 1, 2017,

with the implementation of final rates in Minnesota, new rates were put into effect for the Minnesota RRA rider to address recovery of federal Production Tax Credits (PTCs) expiring on OTP’s wind farms in

2017

and

2018.

North Dakota

General Rates

—On

November 2, 2017

OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates of

$13.1

 million or

8.72%.

The

$13.1

million increase is net of reductions in North Dakota RRA, TCR and ECR rider revenues that will result from a lower allowed rate of return on equity and changes in allocation factors in the general rate case. In the request, OTP proposed an allowed return on rate base of

7.97%

and an allowed rate of return on equity of

10.30%.

On

December 20, 2017

the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by

$12.8

million, effective

January 1, 2018.

OTP used the same rate of return on equity in the calculation of interim rates as the rate of return on equity used in its

2018

test-year rate request. In response to the reduction in the federal corporate tax rate under the TCJA, the NDPSC issued an order on

February 27, 2018

reducing OTP’s annual revenue requirement for interim rates by

$4.5

million to

$8.3

million, effective

March 1, 2018.

On

March 23, 2018

OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from

$13.1

million to

$7.1

million, a

4.8%

annual increase. The

$6.0

million decrease includes

$4.8

 million related to tax reform and

$1.2

million related to other updates. OTP will continue to address the impacts of the TJCA in its current general rate case.

OTP’s most recently approved 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 which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.

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.

Environmental Cost Recovery Rider

—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS) projects. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s North Dakota share of reagent and emission allowance costs.

South Dakota

General Rate

s

—On

April 20, 2018

OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately

$3.3

million annually, or

10.1%,

as the

first

step in a

two

-step request. OTP requested an interim rate increase effective

May 21, 2018

while the SDPUC considers OTP’s overall request. The SDPUC is scheduled to review the application and act on the request for interim rates on

May 15, 2018. 

The full effects of the TCJA on South Dakota revenue requirements will be addressed in OTP’s current general rate case and incorporated into final rates at the conclusion of that case. The

second

step in the request is an additional

1.7%

increase to be effective

January 1, 2020

to recover costs for a wind generation facility scheduled to be in service by the end of

2019.

OTP’s most recently approved 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.

Environmental Cost Recovery Rider

—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

Reagent Costs and Emission Allowances

—The SDPUC has approved the recovery of reagent and emission allowance costs in OTP’s South Dakota Fuel Clause Adjustment rider.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the

three

-month periods ended

March 31:

Rate Rider (in thousands)	2018			2017
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,516		$	1,966
Transmission Cost Recovery		(29	)		2,170
Environmental Cost Recovery		(31	)		2,824
Renewable Resource Recovery		525			--
North Dakota
Renewable Resource Adjustment		1,967			1,770
Transmission Cost Recovery		2,062			2,511
Environmental Cost Recovery		1,821			2,488
South Dakota
Transmission Cost Recovery		536			441
Environmental Cost Recovery		520			597
Conservation Improvement Program Costs and Incentives		229			240
Total	$	10,116		$	15,007

1

Includes MNCIP costs recovered in base rates.

Rate Rider Updates

The following table provides summary information on the status of updates since

January 1, 2016

for the rate riders described above:

Rate Rider	R - Request Date A - Approval Date	Effective Date Requested or Approved	Annual Revenue ($000s)			Rate
Minnesota
Conservation Improvement Program
2017 Incentive and Cost Recovery	R – March 31, 2018	October 1, 2018	$	10,400		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
2015 Incentive and Cost Recovery	A – July 19, 2016	October 1, 2016	$	8,590		$0.00275/kwh
Transmission Cost Recovery
2017 Rate Reset 1	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	4,736		Various
2015 Annual Update	A – March 9, 2016	April 1, 2016	$	7,203		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of base
Renewable Resource Adjustment
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	9,650		7.493% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	9,989		7.756% of base
2016 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.005% of base
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7.573% of base
Transmission Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,469		Various
2017 Annual Update	A – November 29, 2017	January 1, 2018	$	7,959		Various
2016 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
Environmental Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,718		5.593% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	8,537		6.629% of base
2017 Annual Update	A – July 12, 2017	August 1, 2017	$	9,917		7.633% of base
2016 Annual Update	A – June 22, 2016	July 1, 2016	$	10,359		7.904% of base
South Dakota
Transmission Cost Recovery
2017 Annual Update	A – February 28, 2018	March 1, 2018	$	1,779		Various
2016 Annual Update	A – February 17, 2017	March 1, 2017	$	2,053		Various
2015 Annual Update	A – February 12, 2016	March 1, 2016	$	1,895		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh
2016 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh

1

Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

TCJA

The TCJA reduced the federal corporate income tax rate from

35%

to

21%.

 Currently, all OTP rates have been developed using a

35%

tax rate. The MPUC, the NDPSC, the SDPUC and the FERC have all initiated dockets or proceedings to assess the impact of the lower income tax rates under the TCJA on electric rates and develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required regulated utilities providing service in Minnesota to make filings by

February 15, 2018

but has

not

made a determination on rate treatment. The SDPUC required initial comments by

February 1, 2018

and indicated that revenues collected after

December 31, 2017

would be subject to refund, pending determination of the impacts of the TCJA. As described above, OTP’s pending general rate cases in North Dakota and South Dakota reflect the impact of the TCJA. OTP has accrued refund liabilities for revenues collected under rates set to recover higher levels of federal income taxes than OTP is currently incurring under the lower federal tax rates in the TCJA. The accrued refund liabilities as of

March 31, 2018

related to the tax rate reduction were

$1.9

million in Minnesota,

$0.8

million in North Dakota and

$0.5

million in South Dakota.

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a

one

-day suspension period, subject to ultimate approval by the FERC.

MVPs—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

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 sought to reduce the

12.38%

ROE used in MISO’s transmission rates to a proposed

9.15%.

The complaint established a

15

-month refund period from

November 12, 2013

to

February 11, 2015.

A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on

December 22, 2015

finding that the MISO transmission owners’ ROE should be

10.32%,

and the FERC issued an order on

September 28, 2016

setting the base ROE at

10.32%.

A number of parties requested rehearing of the

September 2016

order and the requests are pending FERC action.

On

November 6, 2014

a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional

50

-basis points for Regional Transmission Organization participation (RTO Adder). On

January 5, 2015

the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the

November 12, 2013

complaint and OTP’s incentive rate filing, OTP’s ROE will be

10.82%

(a

10.32%

base ROE plus the

0.5%

RTO Adder) effective

September 28, 2016.

On

February 12, 2015

another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP,

may

collect under the MISO Tariff from

12.38%

to a proposed

8.67%.

This

second

complaint established a

second

15

-month refund period from

February 12, 2015

to

May 11, 2016.

The FERC issued an order on

June 18, 2015

setting the complaint for hearings before an ALJ, which were held the week of

February 16, 2016.

A non-binding decision by the presiding ALJ was issued on

June 30, 2016

finding that the MISO transmission owners’ ROE should be

9.7%.

OTP is currently waiting for the issuance of a FERC order on the

second

complaint.

Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a

$2.7

million liability on its balance sheet as of

December 31, 2016,

representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the

first

15

-month refund period in its

February

and

June 2017

billings. The refund, in combination with a decision in the

2016

Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from

$2.7

 million on

December 31, 2016

to

$1.6

million as of

March 31, 2018.

In

June 2014,

the FERC adopted a

two

-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the

two

ROE complaints involving MISO transmission owners discussed above. In

April 2017

the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s

June 2014

ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had

not

properly determined that the ROE authorized for NETOs prior to

June 2014

was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the

April 2017

action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required. On

September 29, 2017

the MISO transmission owners filed a motion to dismiss the

second

complaint based on the D.C. Circuit decision in the NETOs complaint. If FERC were to act on a motion to dismiss, it would eliminate the refund obligation from the

second

complaint and the ROE from the

first

complaint would remain in effect.

XML

Note 4 - Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Schedule of Regulatory Assets and Liabilities [Text Block]

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, environmental upgrades and conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	March 31, 2018								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	9,090	$	110,214		$	119,304		see below
Conservation Improvement Program Costs and Incentives 2		5,313		3,468			8,781			30
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,779			6,779		asset lives
Deferred Marked-to-Market Losses 1		3,463		1,989			5,452			33
Big Stone II Unrecovered Project Costs – Minnesota 1		657		1,467			2,124			37
Debt Reacquisition Premiums 1		246		904			1,150			174
Big Stone II Unrecovered Project Costs – South Dakota 1		100		417			517			62
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		374		--			374			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		322		--			322			12
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		196			196		asset lives
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1		--		166			166		see below
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		133		--			133			21
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		--		67			67			21
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		38		--			38			1
Total Regulatory Assets	$	19,736	$	125,667		$	145,403
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	148,938		$	148,938		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		84,223			84,223		asset lives
Refundable Fuel Clause Adjustment Revenues		2,414		--			2,414			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,161		--			1,161			7
North Dakota Renewable Resource Recovery Rider Accrued Refund		371		--			371			9
North Dakota Environmental Cost Recovery Rider Accrued Refund		351		--			351			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		317		--			317			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		304		--			304			7
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		68		36			104			21
Other		6		82			88			189
South Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		37		--			37			7
Revenue for Rate Case Expenses Subject to Refund – Minnesota		30		--			30			1
Total Regulatory Liabilities	$	5,119	$	233,279		$	238,398
Net Regulatory Asset/(Liability) Position	$	14,617	$	(107,612	)	$	(92,995	)

1

Costs subject to recovery

excluding

a rate of return.

2

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

	December 31, 2017								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	9,090	$	112,487		$	121,577		see below
Conservation Improvement Program Costs and Incentives 2		7,385		2,774			10,159			21
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,651			6,651		asset lives
Deferred Marked-to-Market Losses 1		4,063		2,405			6,468			36
Big Stone II Unrecovered Project Costs – Minnesota 1		650		1,636			2,286			40
Debt Reacquisition Premiums 1		254		960			1,214			177
Big Stone II Unrecovered Project Costs – South Dakota 1		100		442			542			65
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		309		--			309			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		75		--			75			12
North Dakota Renewable Resource Rider Accrued Revenues 2		206		236			442			15
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		--		1,985			1,985			24
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		267		--			267			4
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		152		--			152			12
Total Regulatory Assets	$	22,551	$	129,576		$	152,127
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	149,052		$	149,052		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,100			83,100		asset lives
Refundable Fuel Clause Adjustment Revenues		5,778		--			5,778			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,667		--			1,667			11
South Dakota Environmental Cost Recovery Rider Accrued Refund		187		--			187			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		409		--			409			12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		132		48			180			24
Other		5		84			89			192
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		802		--			802			10
Revenue for Rate Case Expenses Subject to Refund – Minnesota		208		--			208			4
Minnesota Southwest Power Pool Transmission Cost Tracker Refund		--		609			609			22
North Dakota Transmission Cost Recovery Rider Accrued Refund		349		--			349			12
Total Regulatory Liabilities	$	9,688	$	232,893		$	242,581
Net Regulatory Asset/(Liability) Position	$	12,863	$	(103,317	)	$	(90,454	)

1

Costs subject to recovery

excluding

a rate of return.

2

Amount 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.

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.

All Deferred Marked-to-Market Losses recorded as of

March 31, 2018

relate to forward purchases of energy scheduled for delivery through

December 2020.

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.

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

174

months.

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.

North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota and are currently being recovered beginning with the establishment of interim rates in

January 2018.

Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers.

The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied.

The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker relates to costs incurred, in excess of the rate at which the costs are being recovered under current rates, that are subject to future recovery under current rates or through future rate adjustments.

North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that have

not

been billed to North Dakota customers as of

March 31, 2018.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had

not

been billed to North Dakota customers as of

December 31, 2017.

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.

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.

North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that had

not

been billed to North Dakota customers as of

December 31, 2017.

The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic

740,

Income Taxes

.

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

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

March 31, 2018.

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

March 31, 2018.

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 and for reagent and emission allowances costs that are recoverable from North Dakota customers as of

March 31, 2018.

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

March 31, 2018.

The Minnesota Renewable Resource 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

March 31, 2018.

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

March 31, 2018.

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

March 31, 2018.

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

March 31, 2018.

The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund.

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.

XML

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Stockholders Equity and Earnings per Share [Text Block]

5

. 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 Loss			Total Common Equity
Balance, December 31, 2017	$	197,787		$	343,450		$	161,286		$	(5,631	)	$	696,892
Common Stock Issuances, Net of Expenses		638			(638	)								--
Common Stock Retirements		(292	)		(2,117	)								(2,409	)
Net Income								26,215						26,215
Other Comprehensive Loss											(502	)		(502	)
Employee Stock Incentive Plans Expense					1,146									1,146
Common Dividends ($0.335 per share)								(13,292	)					(13,292	)
Balance, March 31, 2018	$	198,133		$	341,841		$	174,209		$	(6,133	)	$	708,050

Shelf Registration

s

and Common Share Distribution Agreement

On

May 3, 2018

the Company 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 3, 2021.

On

May 3, 2018,

the Company also filed a shelf registration statement with the SEC for the issuance of up to

1,500,000

common shares under the Company's Automatic Dividend Reinvestment (DRIP) and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan to be either new issue common shares or common shares purchased in the open market. The shelf registration for the DRIP expires on

May 3, 2021.

The shelf registration statements replaced the Company’s prior shelf registration statements that were due to expire on

May 11, 2018.

On

May 1, 2018

the Company’s Distribution Agreement with J.P. Morgan Securities (JPMS) ended as required under the agreement. This Distribution Agreement allowed the Company to offer and sell its common shares from time to time in an At-the-Market (ATM) offering program through JPMS, up to an aggregate sales price of

$75

million. The Company expects to establish a new ATM offering program under which the Company

may

offer and sell its common shares from time to under the shelf registration statement.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from

December 31, 2017

through

March 31, 2018:

Common Shares Outstanding, December 31, 2017	39,557,491
Issuances:
Executive Stock Performance Awards (2015 shares earned)	114,648
Vesting of Restricted Stock Units	12,950
Retirements:
Shares Withheld for Individual Income Tax Requirements	(58,495	)
Common Shares Outstanding, March 31, 2018	39,626,594

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the

three

-month periods ended

March 31, 2018

and

2017.

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 for the

three

-month periods ended

March 31:

	2018		2017
Weighted Average Common Shares Outstanding – Basic		39,550,874		39,350,802
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		223,162		201,639
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		59,130		57,873
Nonvested Restricted Shares		27,643		27,069
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,873		3,342
Total Dilutive Shares		312,808		289,923
Weighted Average Common Shares Outstanding – Diluted		39,863,682		39,640,725

The effect of dilutive shares on earnings per share for the

three

-month periods ended

March 31, 2018

and

2017,

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.

XML

Note 6 - Share-based Payments

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

6

. Share-Based Payments

Stock Incentive Awards

On

February 5, 2018

the following stock incentive awards were granted to officers under the

2014

Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant- Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,200	$	41.325	25% per year through February 6, 2022
Stock Performance Awards Granted		54,000	$	35.73	December 31, 2020

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

Under the performance share awards the aggregate award for performance at target is

54,000

shares. For target performance the participants would earn an aggregate of

27,000

common shares for achieving the target set for the Company’s

3

-year average adjusted return on equity. The participants would also earn an aggregate of

27,000

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, 2018

through

December 31, 2020,

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, 2018

and the average closing price for the

20

trading days immediately preceding

January 1, 2021.

Actual payment

may

range from

zero

to

150%

of the target amount, or up to

81,000

common shares. There are

no

voting or dividend rights related to these awards until the shares, if any, are issued at the end of the performance measurement period. 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 an officer who is party to an Executive Employment Agreement with the Company is to be made at target at the date of any such event. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC

718,

and will be measured over the performance period based on the grant-date fair value of the award. The grant-date fair value of each performance share award was determined using a Monte Carlo fair valuation simulation model.

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

As of

March 31, 2018,

the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately

$5.9

million (before income taxes) which will be amortized over a weighted-average period of

2.2

years.

Amounts of compensation expense recognized under the Company’s

six

stock-based payment programs for the

three

-month periods ended

March 31, 2018

and

2017

are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2018		2017
Stock Performance Awards Granted to Executive Officers	$	651	$	649
Restricted Stock Units Granted to Executive Officers		249		264
Restricted Stock Granted to Executive Officers		16		22
Restricted Stock Granted to Directors		166		128
Restricted Stock Units Granted to Non-Executive Employees		64		87
Totals	$	1,146	$	1,150

XML

Note 7 - Retained Earnings and Dividend Restriction

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Retained Earnings Restrictions [Text Block]

7

. Retained Earnings

and Dividend

Restriction

The Company is a holding company with

no

significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did

not

meet certain financial covenants. As of

March 31, 2018,

the Company was in compliance with these financial covenants. See note

9

to consolidated financial statements 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, the 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

47.4%

and

58.0%

based on OTP’s

2017

capital structure petition approved by order of the MPUC on

September 1, 2017.

As of

March 31, 2018,

OTP’s equity-to-total-capitalization ratio including short-term debt was

51.6%

and its net assets restricted from distribution totaled approximately

$481,000,000.

Total capitalization for OTP cannot currently exceed

$1,178,024,000.

XML

Note 8 - Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

8

. Commitments and Contingencies

Construction and Other Purchase Commitments

At

March 31, 2018

OTP had commitments under contracts, including its share of construction program commitments, extending into

2019

of approximately

$37.5

million. At

December 31, 2017

OTP had commitments under contracts, including its share of construction program commitments, extending into

2019

of approximately

$41.0

million. At

March 31, 2018

T.O. Plastics had commitments for the purchase of resin through

December 31, 2021

of approximately

$6.2

million. At

December 31, 2017

T.O. Plastics had commitments for the purchase of resin through

December 31, 2021

of approximately

$6.7

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

2041.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of

2019

and

2040,

respectively. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant 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. In the

first

quarter of

2018,

OTP entered into an agreement to lease rail cars for transporting coal to Hoot Lake Plant. The lease period runs from

April 2018

through

May 2021,

increasing OTP’s commitments under operating leases by

$243,000

in

2018,

$324,000

in

2019,

$324,000

in

2020

and

$135,000

in

2021.

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

Contingencies

OTP had a

$1.6

million refund liability on its balance sheet as of

March 31, 2018

representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of the FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate.

Together with as many as

200

utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on

April 1, 2005

until the conclusion of the proceedings on

May 2, 2015.

The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to

not

resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. Final briefs were filed on

January 26, 2018.

Oral arguments occurred on

May 2, 2018.

A final decision is anticipated in the summer of

2018.

MISO has

not

made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have an adverse effect on the Company’s results of operations.

Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as

$1.0

million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

In

2014

the Environmental Protection Agency (EPA) published both proposed standards of performance for carbon dioxide (

CO2

) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed

CO2

emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under Section

111

of the Clean Air Act. The EPA published final rules for each of these proposals on

October 23, 2015.

Both rules were challenged on legal grounds. On

February 9, 2016

the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on

September 27, 2016

before the full court, and a decision was expected in the

first

half of

2017.

However, pursuant to Executive Order

13783,

Promoting Energy Independence and Economic Growth, the EPA was directed to consider suspending, revising

or rescinding the

CO2

rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On

October 16, 2017

the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.

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

March 31, 2018

will

not

be material.

XML

Note 9 - Short-term and Long-term Borrowings

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Debt Disclosure [Text Block]

9

. Short-Term and Long-Term Borrowings

The following table presents the status of the Company’s lines of credit as of

March 31, 2018

and

December 31, 2017:

(in thousands)	Line Limit		In Use on March 31, 2018		Restricted due to Outstanding Letters of Credit		Available on March 31, 2018		Available on December 31, 2017
Otter Tail Corporation Credit Agreement	$	130,000	$	6,182	$	--	$	123,818	$	130,000
OTP Credit Agreement		170,000		24,137		300		145,563		57,239
Total	$	300,000	$	30,319	$	300	$	269,381	$	187,239

Debt

Issuances

2018

Note Purchase Agreement

On

November 14, 2017,

OTP entered into a Note Purchase Agreement (the

2018

Note Purchase Agreement) with the purchasers named therein, pursuant to which OTP agreed to issue to the purchasers, in a private placement transaction,

$100

 million aggregate principal amount of OTP’s

4.07%

Series

2018A

Senior Unsecured Notes due

February 7, 2048 (

the

2018

Notes). The

2018

Notes were issued on

February 7, 2018.

Proceeds from the

2018

Notes were used to repay outstanding borrowings under the OTP Credit Agreement.

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 so prepaid, together with unpaid accrued interest and a make-whole amount; provided that if

no

default or event of default exists under the Note Purchase Agreement, any prepayment made by OTP of all of the Notes then outstanding on or after

August 7, 2047

will be made without any make-whole amount. The

2018

Note Purchase Agreement also requires OTP to offer to prepay all outstanding Notes at

100%

of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the

2018

Note Purchase Agreement) of OTP.

The

2018

Note Purchase Agreement contains a number of restrictions on the business of OTP. These include restrictions on OTP’s abilities 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

2018

Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants. The

2018

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

2018

Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event the OTP 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

2018

Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the

2018

Notes than any analogous provision contained in the

2018

Note Purchase Agreement (Additional Covenant), then unless waived by the Required Holders (as defined in the

2018

Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the

2018

Note Purchase Agreement. The

2018

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.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of

March 31, 2018

and

December 31, 2017:

March 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	24,137	$	6,182	$	30,319
Long-Term Debt:
3.55% Guaranteed Senior Notes, due December 15, 2026			$	80,000	$	80,000
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
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048		100,000				100,000
North Dakota Development Note, 3.95%, due April 1, 2018				7		7
PACE Note, 2.54%, due March 18, 2021				644		644
Total	$	512,000	$	80,651	$	592,651
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		171		171
Unamortized Long-Term Debt Issuance Costs		2,091		446		2,537
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	509,909	$	80,034	$	589,943
Total Short-Term and Long-Term Debt (with current maturities)	$	534,046	$	86,387	$	620,433

December 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	112,371	$	--	$	112,371
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	--	$	--
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
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				27		27
PACE Note, 2.54%, due March 18, 2021				684		684
Total	$	412,000	$	80,711	$	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		186		186
Unamortized Long-Term Debt Issuance Costs		1,684		461		2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,316	$	80,064	$	490,380
Total Short-Term and Long-Term Debt (with current maturities)	$	522,687	$	80,250	$	602,937

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Note 10 - Pension Plan and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Pension and Other Postretirement Benefits Disclosure [Text Block]

1

0

.

Pension Plan and Other Postretirement Benefits

Pension Plan

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

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	1,615		$	1,407
Interest Cost on Projected Benefit Obligation		3,363			3,534
Expected Return on Assets		(5,300	)		(4,807	)
Amortization of Prior-Service Cost:
From Regulatory Asset		4			30
From Other Comprehensive Income 1		--			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,784			1,273
From Other Comprehensive Income 1		44			31
Net Periodic Pension Cost 2	$	1,510		$	1,469
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs :
C osts included in OTP c apital e xpenditures	$	328		$	285
Service c osts included in e lectric o peration and m aintenance e xpenses		1,247			1,100
Service c osts included in o ther n onelectric e xpenses		40			34
Nonservice costs capitalized as regulatory assets		(21	)		--
Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits		(84	)		50

Cash flows

— The Company had

no

minimum funding requirement as of

December 31, 2017

but made discretionary plan contributions totaling

$20

million in the quarter ended

March 31, 2018.

Executive Survivor and Supplemental Retirement Plan

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

	Three Months Ended March 31,
(in thousands)	2018		2017
Service Cost—Benefit Earned During the Period	$	100	$	73
Interest Cost on Projected Benefit Obligation		399		422
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income 1		10		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		67		71
From Other Comprehensive Income 1		165		110
Net Periodic Pension Cost 2	$	745	$	689
1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice c ost c omponents of p ostretirement b enefits on the face of the Company’s consolidated statements of income.
2 Allocation of Costs :
Service c osts included in e lectric o peration and m aintenance e xpenses	$	25	$	24
Service costs included in ot her n onelectric e xpenses		75		49
Nonservice c osts included in n onservice c ost c omponents of p ostretirement b enefits		645		616

Postretirement Benefits

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

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	382		$	356
Interest Cost on Projected Benefit Obligation		645			678
Amortization of Net Actuarial Loss:
From Regulatory Asset		412			233
From Other Comprehensive Income 1		10			6
Net Periodic Postretirement Benefit Cost 2	$	1,449		$	1,273
Effect of Medicare Part D Subsidy	$	(37	)	$	(140	)
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs :
C osts included in OTP c apital e xpenditures	$	78		$	247
Service c osts included in e lectric operation and maintenance expenses		294			278
Service c osts included in o ther n onelectric e xpenses		10			9
Nonservice costs capitalized as regulatory assets		217			--
Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits		850			739

XML

Note 11 - Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Fair Value Disclosures [Text Block]

1

1

. Fair Value of Financial Instruments

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

Cash Equivalents

—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt

—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of

March 31, 2018

and

December 31, 2017

related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of

LIBOR

plus

1.50%

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 fair value measurements of the Company’s long-term debt issues fall into level

2

of the fair value hierarchy set forth in ASC 

820.

	March 31, 2018						December 31, 2017
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	1,121		$	1,121		$	16,216		$	16,216
Short-Term Debt		(30,319	)		(30,319	)		(112,371	)		(112,371	)
Long-Term Debt including Current Maturities		(590,114	)		(614,873	)		(490,566	)		(543,691	)

XML

Note 13 - Income Tax Expense - Continuing Operations

3 Months Ended

Mar. 31, 2018

Notes to Financial Statements

Income Tax Disclosure [Text Block]

1

3

. Income Tax Expense

– Continuing Operations

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the

three

-month periods ended

March 31, 2018

and

2017:

	Three Months Ended March 31,
(in thousands)	2018			2017
Income Before Income Taxes – Continuing Operations	$	30,009		$	25,892
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017)		7,802			10,098
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,120	)		(2,052	)
Property Related Differences and Other Regulatory Adjustments		(1,073	)		105
Excess Tax Deduction – Equity Method Stock Awards		(624	)		(697	)
Other Comprehensive Income Deferred Tax Rate Adjustment		(531	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(212	)
Research and Development and Other Tax Credits		(180	)		(157	)
Allowance for Funds Used During Construction – Equity		(167	)		(67	)
Corporate Owned Life Insurance		(8	)		(294	)
Section 199 Domestic Production Activities Deduction		--			(330	)
Other Items – Net		(47	)		(31	)
Income Tax Expense – Continuing Operations	$	3,794		$	6,363
Effective Income Tax Rate – Continuing Operations		12.6	%		24.6	%

The following table summarizes the activity related to the Company’s unrecognized tax benefits:

(in thousands)	2018			2017
Balance on January 1	$	684		$	891
Decreases Related to Tax Positions for Prior Years		(44	)		--
Increases Related to Tax Positions for Current Year		36			43
Uncertain Positions Resolved During Year		--			--
Balance on March 31	$	676		$	934

The balance of unrecognized tax benefits as of

March 31, 2018

would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of

March 31, 2018

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

March 31, 2018.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of

May 1, 2018,

with limited exceptions, the Company is

no

longer subject to examinations by taxing authorities for tax years prior to

2014

for federal, Minnesota and North Dakota income taxes.

XML

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

Accounting Policies [Abstract]

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

In

May 2014

the Financial Accounting Standards Board (FASB) issued a major update to the Accounting Standards Codification (ASC), Accounting Standards Update (ASU)

No.

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

(ASC

606

). The Company adopted the updates in ASC

606

effective

January 1, 2018

on a modified retrospective basis but did

not

record a cumulative effect adjustment to retained earnings on application of the updates because the adoption of the updates in ASC

606

had

no

material impact on the timing of revenue recognition for the Company or its subsidiaries. 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.

Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has

not

identified any contracts where the timing of revenue recognition will change as a result of the adoption of the updates in ASC

606.

Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends.

In addition to recognizing revenue from contracts with customers under ASC

606,

the Company also records adjustments to Electric segment revenues for amounts subject to future collection or refund under alternative revenue programs (ARPs) as defined in ASC Topic

980,

Regulated Operations

(ASC

980

). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do

not

meet the criteria to be classified as revenue from contracts with customers.

Electric Segment Revenues

—In the Electric segment, the Company recognizes revenue in

two

categories: (

1

) revenues from contracts with customers and (

2

) adjustments to revenues for amounts collectible or refundable under ARPs.

Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A

third

source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer.

ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning incentives or returns on investments subject to recovery under several ARP rate riders, including:

● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders.

● In North Dakota: TCR, ECR and RRA riders

● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders.

OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note

3

for total revenues billed and accrued under ARP riders for the

three

-month periods ended

March 31, 2018

and

2017.

Manufacturing

Segment Revenues

—Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped and adjusts the revenue for volume rebate variable pricing considerations the company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on products when shipped, the operating companies have

no

further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point.

Plastics Segment Revenues

—Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl-chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. Billed amounts of revenue recognized are adjusted for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. For revenue recognized on shipped products, there is

no

further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. The Plastics segment has

one

customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is also recognized over time as the pipe is stored.

See operating revenue table in note

2

to consolidated financial statements for a disaggregation of the Company’s revenues by business segment for the

three

-month periods ended

March 31, 2018

and

2017.

Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block]

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according 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 of Financial Instruments, Policy [Policy Text Block]

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 hierarchical 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.

Level

2

– Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level

2

are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level

3

– Significant inputs to pricing have little or

no

observability as of the reporting date. The types of assets and liabilities included in Level

3

are those with inputs requiring significant management judgment or estimation and

may

include complex and subjective models and forecasts.

The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of

March 31, 2018

and

December 31, 2017:

March 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,220
Corporate Debt Securities – Held by Captive Insurance Company			$	5,341
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,779
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		870
Total Assets	$	2,090	$	7,120

December 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,285
Corporate Debt Securities – Held by Captive Insurance Company			$	5,373
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,787
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		823
Total Assets	$	2,108	$	7,160

The valuation techniques and inputs used for the Level

2

fair value measurements in the table above are as follows:

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.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

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 paid by the Coyote Station owners under the LSA reflects 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.

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. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of

March 31, 2018

could be as high as

$56.5

 million, OTP’s

35%

share of unrecovered costs.

Inventory, Policy [Policy Text Block]

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

	March 31,		December 31,
(in thousands)	2018		2017
Finished Goods	$	25,341	$	26,605
Work in Process		17,224		14,222
Raw Material, Fuel and Supplies		45,434		47,207
Total Inventories	$	87,999	$	88,034

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of

December 31, 2017

indicated the fair values are substantially in excess of their respective book values and

not

impaired.

The following table indicates there were

no

changes to goodwill by business segment during the

first

three

months of

2018:

(in thousands)	Gross Balance December 31, 2017		Accumulated Impairments		Balance (net of impairments) December 31, 2017		Adjustments to Goodwill in 2018		Balance (net of impairments) March 31, 2018
Manufacturing	$	18,270	$	--	$	18,270	$	--	$	18,270
Plastics		19,302		--		19,302		--		19,302
Total	$	37,572	$	--	$	37,572	$	--	$	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

March 31, 2018

and

December 

31,

 

2017:

March 31 , 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	9,277	$	13,214	21	-	209
Covenant not to Compete		590		508		82		5
Other		154		30		124		29
Total	$	23,235	$	9,815	$	13,420

December 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,994	$	13,497	24	-	212
Covenant not to Compete		590		459		131		8
Other		154		17		137		32
Total	$	23,235	$	9,470	$	13,765

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Amortization Expense – Intangible Assets	$	345	$	332

The estimated annual amortization expense for these intangible assets for the next

five

years is:

(in thousands)	2018		2019		2020		2021		2022
Estimated Amortization Expense – Intangible Assets	$	1,315	$	1,184	$	1,133	$	1,099	$	1,099

Cash Flow Supplemental [Policy Text Block]

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2018		2017
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,451	$	10,811

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards Adopted

ASU

2014

-

09

—In

May 2014

the FASB issued ASU

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

.

The Company adopted the updates in ASC

606

effective

January 1, 2018

on a modified retrospective basis. See disclosures above under Revenue Recognition.

ASU

2016

-

01

—In

January 2016

the FASB issued ASU

No.

2016

-

01,

Financial Instruments—Overall

(Subtopic

825

-

10

)

(ASU

2016

-

01

). The amendments in ASU

2016

-

01

address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments and require equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. For the Company, the amendments in ASU

2016

-

01are

effective for fiscal years beginning after

December 15, 2017,

including interim periods within those fiscal years. The Company adopted the updates in ASU

2016

-

01

in the

first

quarter of

2018,

which resulted in changes in the fair value of equity instruments held as investments by the Company’s captive insurance company being classified in net income. The fair value of equity instruments held by the Company’s captive insurance company on

March 31, 2018

were

$1,220,000

and the amount of unrealized gains on those investments recorded in net income in the

first

quarter of

2018

was

$87,000.

ASU

2017

-

07

—In

March 2017

the FASB issued ASU

No.

2017

-

07,

Compensation—Retirement Benefits (Topic

715

): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

(ASU

2017

-

07

), with the intent of improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic

715,

Compensation—Retirement Benefits

(ASC

715

)

,

does

not

prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does

not

require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets. The amendments in ASU

2017

-

07

require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period, which the Company has provided in the electric operation and maintenance and other nonelectric expense lines on its income statement. The other components of net benefit cost as defined in ASC

715

are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The Company has provided the amount of the non-service cost components of net periodic postretirement benefit costs in a separate line below interest expense on the face of its consolidated income statement. The amendments in ASU

2017

-

07

also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU

2017

-

07

are effective for annual periods beginning after

December 15, 2017,

including interim periods within those annual periods. The amendments have been applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the Company’s consolidated income statements and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit cost in assets.

The majority of the Company’s benefit costs to which the amendments in ASU

2017

-

07

apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU

2017

-

07

deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs applicable to OTP, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all the components of net periodic pension costs as recoverable operating expenses. The Company has assessed the impact adoption of the amendments in ASU

2017

-

07

will have on its consolidated financial statements, financial position and results of operations and OTP has established regulatory assets to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under ASU

2017

-

07.

The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in

2017

that would have been recorded as regulatory assets if the amendments in ASU

2017

-

07

were applicable in

2017

were

$0.8

million. The Company’s non-service costs components of net periodic postretirement benefit costs included in operating expense in

2017

and

2016

that will be reported in other income and deductions in the Company's

2018

 annual report on Form

10

-K after adoption of ASU

2017

-

07

were

$5.6

million for

2017

and

$5.1

million for

2016.

Additional information on the allocation of postretirement benefit costs for the

three

-month periods ended

March 31, 2018

and

2017

is provided in note

10

to these consolidated financial statements for the Company’s major benefit programs presented.

New Accounting Standards Pending Adoption

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 Generally Accepted Accounting Principles in the United States (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 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 has developed a list of all current leases outstanding and continues to review ASU

2016

-

02,

identifying key impacts to its businesses to determine areas where the amendments in ASU

2016

-

02

will be applicable and is 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

2017

-

04

—In

January 2017

the FASB issued ASU

No.

2017

-

04,

Intangibles—Goodwill and Other (Topic

350

): Simplifying the Test for Goodwill Impairment

(ASU

2017

-

04

), which simplifies how an entity is required to test goodwill for impairment by eliminating Step

2

from the goodwill impairment test. Step

2

measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step

2,

an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU

2017

-

04,

an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will

not

exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in ASU

2017

-

04

modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity

no

longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step

2

from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU

2017

-

04

are effective for annual or any interim goodwill impairment tests in fiscal years beginning after

December 15, 2019.

Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after

January 1, 2017.

ASU

201

8

-

0

2

—In

February 2018

the FASB issued ASU

No.

2018

-

02,

Income Statement—Reporting Comprehensive Income (Topic

220

):

Reclassification of Certain Tax Effects from

Accumulated Other Comprehensive Income

(ASU

2018

-

02

). The amendments in ASU

2018

-

02,

which are narrow in scope, allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. Consequently, the amendments eliminate the stranded tax effects resulting from the

2017

Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users. The amendments in ASU

2018

-

02

also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after

December 15, 2018,

and interim periods within those fiscal years. Early adoption of the amendments in ASU

2018

-

02

is permitted. The amendments in ASU

2018

-

02

can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company does

not

plan to adopt the amendments in ASU

2018

-

02

until the

first

quarter of

2019.

On adoption, the Company will reclassify the

$784,000

of income tax effects of the TCJA on the gross deferred tax amounts at the date of enactment of the TCJA related to items remaining in accumulated other comprehensive income from other comprehensive income to retained earnings so that the remaining gross deferred tax amounts related to items in other comprehensive income will reflect current effective tax rates.

XML

Note 1 - Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

March 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,220
Corporate Debt Securities – Held by Captive Insurance Company			$	5,341
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,779
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		870
Total Assets	$	2,090	$	7,120

December 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,285
Corporate Debt Securities – Held by Captive Insurance Company			$	5,373
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,787
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		823
Total Assets	$	2,108	$	7,160

Schedule of Inventory, Current [Table Text Block]

	March 31,		December 31,
(in thousands)	2018		2017
Finished Goods	$	25,341	$	26,605
Work in Process		17,224		14,222
Raw Material, Fuel and Supplies		45,434		47,207
Total Inventories	$	87,999	$	88,034

Schedule of Goodwill [Table Text Block]

(in thousands)	Gross Balance December 31, 2017		Accumulated Impairments		Balance (net of impairments) December 31, 2017		Adjustments to Goodwill in 2018		Balance (net of impairments) March 31, 2018
Manufacturing	$	18,270	$	--	$	18,270	$	--	$	18,270
Plastics		19,302		--		19,302		--		19,302
Total	$	37,572	$	--	$	37,572	$	--	$	37,572

Schedule of Other Intangible Assets [Table Text Block]

March 31 , 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	9,277	$	13,214	21	-	209
Covenant not to Compete		590		508		82		5
Other		154		30		124		29
Total	$	23,235	$	9,815	$	13,420

December 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,994	$	13,497	24	-	212
Covenant not to Compete		590		459		131		8
Other		154		17		137		32
Total	$	23,235	$	9,470	$	13,765

Finite-lived Intangible Assets Amortization Expense [Table Text Block]

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Amortization Expense – Intangible Assets	$	345	$	332

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

(in thousands)	2018		2019		2020		2021		2022
Estimated Amortization Expense – Intangible Assets	$	1,315	$	1,184	$	1,133	$	1,099	$	1,099

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	As of March 31,
(in thousands)	2018		2017
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,451	$	10,811

XML

Note 2 - Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	109,180		$	106,454
Changes in Accrued ARP Revenues		(875	)		(1,239	)
Total Retail Sales Revenue		108,305			105,215
Wholesale Revenues – Company Generation		1,015			867
Other Revenues		13,645			12,469
Total Electric Segment Revenues	$	122,965		$	118,551
Manufacturing Segment:
Metal Parts and Tooling	$	56,927		$	48,078
Plastic Products		10,235			9,552
Other		1,500			787
Total Manufacturing Segment Revenues	$	68,662		$	58,417
Plastics Segment – Sale of PVC Pipe Products	$	49,653		$	37,157
Intersegment Eliminations	$	(14	)	$	(8	)
Total	$	241,266		$	214,117

	Three Months Ended
	March 31,
(in thousands)	2018		2017
Electric	$	6,390	$	6,386
Manufacturing		554		554
Plastics		150		153
Corporate and Intersegment Eliminations		278		369
Total	$	7,372	$	7,462

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	2,098		$	6,062
Manufacturing		1,223			1,055
Plastics		2,414			1,390
Corporate		(1,941	)		(2,144	)
Total	$	3,794		$	6,363

	Three Months Ended
	March 31,
(in thousands)	2018			2017
Electric	$	16,668		$	15,560
Manufacturing		4,164			2,172
Plastics		6,844			2,437
Corporate		(1,461	)		(640	)
Discontinued Operations		--			56
Total	$	26,215		$	19,585

	March 31,		December 31,
(in thousands)	2018		2017
Electric	$	1,686,255	$	1,690,224
Manufacturing		180,319		167,023
Plastics		97,953		87,230
Corporate		42,891		59,801
Total	$	2,007,418	$	2,004,278

XML

Note 3 - Rate and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Revenues Recorded under Rate Riders [Table Text Block]

Rate Rider (in thousands)	2018			2017
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,516		$	1,966
Transmission Cost Recovery		(29	)		2,170
Environmental Cost Recovery		(31	)		2,824
Renewable Resource Recovery		525			--
North Dakota
Renewable Resource Adjustment		1,967			1,770
Transmission Cost Recovery		2,062			2,511
Environmental Cost Recovery		1,821			2,488
South Dakota
Transmission Cost Recovery		536			441
Environmental Cost Recovery		520			597
Conservation Improvement Program Costs and Incentives		229			240
Total	$	10,116		$	15,007

Schedule of Information on Status of Updates for Previous Periods [Table Text Block]

Rate Rider	R - Request Date A - Approval Date	Effective Date Requested or Approved	Annual Revenue ($000s)			Rate
Minnesota
Conservation Improvement Program
2017 Incentive and Cost Recovery	R – March 31, 2018	October 1, 2018	$	10,400		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
2015 Incentive and Cost Recovery	A – July 19, 2016	October 1, 2016	$	8,590		$0.00275/kwh
Transmission Cost Recovery
2017 Rate Reset 1	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	4,736		Various
2015 Annual Update	A – March 9, 2016	April 1, 2016	$	7,203		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of base
Renewable Resource Adjustment
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	9,650		7.493% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	9,989		7.756% of base
2016 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.005% of base
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7.573% of base
Transmission Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,469		Various
2017 Annual Update	A – November 29, 2017	January 1, 2018	$	7,959		Various
2016 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
Environmental Cost Recovery
2018 Rate Reset for effect of TCJA	A – February 27, 2018	March 1, 2018	$	7,718		5.593% of base
2017 Rate Reset	A – December 20, 2017	January 1, 2018	$	8,537		6.629% of base
2017 Annual Update	A – July 12, 2017	August 1, 2017	$	9,917		7.633% of base
2016 Annual Update	A – June 22, 2016	July 1, 2016	$	10,359		7.904% of base
South Dakota
Transmission Cost Recovery
2017 Annual Update	A – February 28, 2018	March 1, 2018	$	1,779		Various
2016 Annual Update	A – February 17, 2017	March 1, 2017	$	2,053		Various
2015 Annual Update	A – February 12, 2016	March 1, 2016	$	1,895		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh
2016 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh

XML

Note 4 - Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Regulatory Assets and Liabilities [Table Text Block]

	March 31, 2018								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	9,090	$	110,214		$	119,304		see below
Conservation Improvement Program Costs and Incentives 2		5,313		3,468			8,781			30
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,779			6,779		asset lives
Deferred Marked-to-Market Losses 1		3,463		1,989			5,452			33
Big Stone II Unrecovered Project Costs – Minnesota 1		657		1,467			2,124			37
Debt Reacquisition Premiums 1		246		904			1,150			174
Big Stone II Unrecovered Project Costs – South Dakota 1		100		417			517			62
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		374		--			374			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		322		--			322			12
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		196			196		asset lives
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1		--		166			166		see below
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		133		--			133			21
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		--		67			67			21
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		38		--			38			1
Total Regulatory Assets	$	19,736	$	125,667		$	145,403
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	148,938		$	148,938		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		84,223			84,223		asset lives
Refundable Fuel Clause Adjustment Revenues		2,414		--			2,414			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,161		--			1,161			7
North Dakota Renewable Resource Recovery Rider Accrued Refund		371		--			371			9
North Dakota Environmental Cost Recovery Rider Accrued Refund		351		--			351			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		317		--			317			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		304		--			304			7
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		68		36			104			21
Other		6		82			88			189
South Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		37		--			37			7
Revenue for Rate Case Expenses Subject to Refund – Minnesota		30		--			30			1
Total Regulatory Liabilities	$	5,119	$	233,279		$	238,398
Net Regulatory Asset/(Liability) Position	$	14,617	$	(107,612	)	$	(92,995	)

	December 31, 2017								Remaining Recovery/
(in thousands)	Current		Long-Term			Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	9,090	$	112,487		$	121,577		see below
Conservation Improvement Program Costs and Incentives 2		7,385		2,774			10,159			21
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,651			6,651		asset lives
Deferred Marked-to-Market Losses 1		4,063		2,405			6,468			36
Big Stone II Unrecovered Project Costs – Minnesota 1		650		1,636			2,286			40
Debt Reacquisition Premiums 1		254		960			1,214			177
Big Stone II Unrecovered Project Costs – South Dakota 1		100		442			542			65
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		309		--			309			12
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		75		--			75			12
North Dakota Renewable Resource Rider Accrued Revenues 2		206		236			442			15
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		--		1,985			1,985			24
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		267		--			267			4
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		152		--			152			12
Total Regulatory Assets	$	22,551	$	129,576		$	152,127
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	149,052		$	149,052		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,100			83,100		asset lives
Refundable Fuel Clause Adjustment Revenues		5,778		--			5,778			12
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,667		--			1,667			11
South Dakota Environmental Cost Recovery Rider Accrued Refund		187		--			187			12
Minnesota Renewable Resource Recovery Rider Accrued Refund		409		--			409			12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		132		48			180			24
Other		5		84			89			192
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
Minnesota Transmission Cost Recovery Rider Accrued Refund		802		--			802			10
Revenue for Rate Case Expenses Subject to Refund – Minnesota		208		--			208			4
Minnesota Southwest Power Pool Transmission Cost Tracker Refund		--		609			609			22
North Dakota Transmission Cost Recovery Rider Accrued Refund		349		--			349			12
Total Regulatory Liabilities	$	9,688	$	232,893		$	242,581
Net Regulatory Asset/(Liability) Position	$	12,863	$	(103,317	)	$	(90,454	)

XML

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Stockholders Equity [Table Text Block]

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Loss			Total Common Equity
Balance, December 31, 2017	$	197,787		$	343,450		$	161,286		$	(5,631	)	$	696,892
Common Stock Issuances, Net of Expenses		638			(638	)								--
Common Stock Retirements		(292	)		(2,117	)								(2,409	)
Net Income								26,215						26,215
Other Comprehensive Loss											(502	)		(502	)
Employee Stock Incentive Plans Expense					1,146									1,146
Common Dividends ($0.335 per share)								(13,292	)					(13,292	)
Balance, March 31, 2018	$	198,133		$	341,841		$	174,209		$	(6,133	)	$	708,050

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

Common Shares Outstanding, December 31, 2017	39,557,491
Issuances:
Executive Stock Performance Awards (2015 shares earned)	114,648
Vesting of Restricted Stock Units	12,950
Retirements:
Shares Withheld for Individual Income Tax Requirements	(58,495	)
Common Shares Outstanding, March 31, 2018	39,626,594

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	2018		2017
Weighted Average Common Shares Outstanding – Basic		39,550,874		39,350,802
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		223,162		201,639
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		59,130		57,873
Nonvested Restricted Shares		27,643		27,069
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,873		3,342
Total Dilutive Shares		312,808		289,923
Weighted Average Common Shares Outstanding – Diluted		39,863,682		39,640,725

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Note 6 - Share-based Payments (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

Award	Shares/Units Granted		Weighted Average Grant- Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,200	$	41.325	25% per year through February 6, 2022
Stock Performance Awards Granted		54,000	$	35.73	December 31, 2020

Share-based Compensation, Activity [Table Text Block]

	Three months ended
	March 31,
(in thousands)	2018		2017
Stock Performance Awards Granted to Executive Officers	$	651	$	649
Restricted Stock Units Granted to Executive Officers		249		264
Restricted Stock Granted to Executive Officers		16		22
Restricted Stock Granted to Directors		166		128
Restricted Stock Units Granted to Non-Executive Employees		64		87
Totals	$	1,146	$	1,150

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Note 9 - Short-term and Long-term Borrowings (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Line of Credit Facilities [Table Text Block]

(in thousands)	Line Limit		In Use on March 31, 2018		Restricted due to Outstanding Letters of Credit		Available on March 31, 2018		Available on December 31, 2017
Otter Tail Corporation Credit Agreement	$	130,000	$	6,182	$	--	$	123,818	$	130,000
OTP Credit Agreement		170,000		24,137		300		145,563		57,239
Total	$	300,000	$	30,319	$	300	$	269,381	$	187,239

Schedule of Debt [Table Text Block]

March 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	24,137	$	6,182	$	30,319
Long-Term Debt:
3.55% Guaranteed Senior Notes, due December 15, 2026			$	80,000	$	80,000
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
Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048		100,000				100,000
North Dakota Development Note, 3.95%, due April 1, 2018				7		7
PACE Note, 2.54%, due March 18, 2021				644		644
Total	$	512,000	$	80,651	$	592,651
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		171		171
Unamortized Long-Term Debt Issuance Costs		2,091		446		2,537
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	509,909	$	80,034	$	589,943
Total Short-Term and Long-Term Debt (with current maturities)	$	534,046	$	86,387	$	620,433

December 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	112,371	$	--	$	112,371
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	--	$	--
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
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				27		27
PACE Note, 2.54%, due March 18, 2021				684		684
Total	$	412,000	$	80,711	$	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		186		186
Unamortized Long-Term Debt Issuance Costs		1,684		461		2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,316	$	80,064	$	490,380
Total Short-Term and Long-Term Debt (with current maturities)	$	522,687	$	80,250	$	602,937

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Note 10 - Pension Plan and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Net Benefit Costs [Table Text Block]

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	1,615		$	1,407
Interest Cost on Projected Benefit Obligation		3,363			3,534
Expected Return on Assets		(5,300	)		(4,807	)
Amortization of Prior-Service Cost:
From Regulatory Asset		4			30
From Other Comprehensive Income 1		--			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,784			1,273
From Other Comprehensive Income 1		44			31
Net Periodic Pension Cost 2	$	1,510		$	1,469
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs :
C osts included in OTP c apital e xpenditures	$	328		$	285
Service c osts included in e lectric o peration and m aintenance e xpenses		1,247			1,100
Service c osts included in o ther n onelectric e xpenses		40			34
Nonservice costs capitalized as regulatory assets		(21	)		--
Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits		(84	)		50

	Three Months Ended March 31,
(in thousands)	2018		2017
Service Cost—Benefit Earned During the Period	$	100	$	73
Interest Cost on Projected Benefit Obligation		399		422
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income 1		10		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		67		71
From Other Comprehensive Income 1		165		110
Net Periodic Pension Cost 2	$	745	$	689
1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice c ost c omponents of p ostretirement b enefits on the face of the Company’s consolidated statements of income.
2 Allocation of Costs :
Service c osts included in e lectric o peration and m aintenance e xpenses	$	25	$	24
Service costs included in ot her n onelectric e xpenses		75		49
Nonservice c osts included in n onservice c ost c omponents of p ostretirement b enefits		645		616

	Three Months Ended March 31,
(in thousands)	2018			2017
Service Cost—Benefit Earned During the Period	$	382		$	356
Interest Cost on Projected Benefit Obligation		645			678
Amortization of Net Actuarial Loss:
From Regulatory Asset		412			233
From Other Comprehensive Income 1		10			6
Net Periodic Postretirement Benefit Cost 2	$	1,449		$	1,273
Effect of Medicare Part D Subsidy	$	(37	)	$	(140	)
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs :
C osts included in OTP c apital e xpenditures	$	78		$	247
Service c osts included in e lectric operation and maintenance expenses		294			278
Service c osts included in o ther n onelectric e xpenses		10			9
Nonservice costs capitalized as regulatory assets		217			--
Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits		850			739

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Note 11 - Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Fair Value, by Balance Sheet Grouping [Table Text Block]

	March 31, 2018						December 31, 2017
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	1,121		$	1,121		$	16,216		$	16,216
Short-Term Debt		(30,319	)		(30,319	)		(112,371	)		(112,371	)
Long-Term Debt including Current Maturities		(590,114	)		(614,873	)		(490,566	)		(543,691	)

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Note 13 - Income Tax Expense - Continuing Operations (Tables)

3 Months Ended

Mar. 31, 2018

Notes Tables

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Three Months Ended March 31,
(in thousands)	2018			2017
Income Before Income Taxes – Continuing Operations	$	30,009		$	25,892
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017)		7,802			10,098
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,120	)		(2,052	)
Property Related Differences and Other Regulatory Adjustments		(1,073	)		105
Excess Tax Deduction – Equity Method Stock Awards		(624	)		(697	)
Other Comprehensive Income Deferred Tax Rate Adjustment		(531	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(212	)
Research and Development and Other Tax Credits		(180	)		(157	)
Allowance for Funds Used During Construction – Equity		(167	)		(67	)
Corporate Owned Life Insurance		(8	)		(294	)
Section 199 Domestic Production Activities Deduction		--			(330	)
Other Items – Net		(47	)		(31	)
Income Tax Expense – Continuing Operations	$	3,794		$	6,363
Effective Income Tax Rate – Continuing Operations		12.6	%		24.6	%

Summary of Income Tax Contingencies [Table Text Block]

(in thousands)	2018			2017
Balance on January 1	$	684		$	891
Decreases Related to Tax Positions for Prior Years		(44	)		--
Increases Related to Tax Positions for Current Year		36			43
Uncertain Positions Resolved During Year		--			--
Balance on March 31	$	676		$	934

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Note 1 - Summary of Significant Accounting Policies (Details Textual)	3 Months Ended		12 Months Ended
	Mar. 31, 2019 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Goodwill, Period Increase (Decrease), Total		$ 0
Pro Forma [Member] | Accounting Standards Update 2017-07 [Member]
Postretirement Benefit Plan, Nonservice Costs Capitalized to Plant in Service During Fiscal Year			$ 800,000
Postretirement Benefit Plan, Nonservice Costs Included in Operating Expense During Fiscal Year			$ 5,600,000	$ 5,100,000
Scenario, Forecast [Member] | Accounting Standards Update 2018-02 [Member]
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 784,000
Equity Instruments Held by the Company's Captive Insurance Company [Member]
Equity Securities, FV-NI		1,220,000
Equity Securities, FV-NI, Unrealized Gain		87,000
Coyote Creek Mining Company, L.L.C. (CCMC) [Member] | Otter Tail Power Company [Member] | Lignite Sales Agreement [Member]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount		$ 56,500,000
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage		35.00%
Plastics [Member]
Number of Customers Under Build and Hold Agreements		1
Goodwill, Period Increase (Decrease), Total

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Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 1 [Member]
Assets:
Total Assets	$ 2,090	$ 2,108
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets:
Investments	1,220	1,285
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets	870	823
Fair Value, Inputs, Level 2 [Member]
Assets:
Total Assets	7,120	7,160
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets:
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Assets:
Investments	5,341	5,373
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments	1,779	1,787
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets

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Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Finished Goods	$ 25,341	$ 26,605
Work in Process	17,224	14,222
Raw Material, Fuel and Supplies	45,434	47,207
Total Inventories	$ 87,999	$ 88,034

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Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Gross Balance		$ 37,572,000
Accumulated Impairments
Balance	$ 37,572,000	37,572,000
Adjustments to Goodwill	0
Manufacturing [Member]
Gross Balance		18,270,000
Accumulated Impairments
Balance	18,270,000	18,270,000
Adjustments to Goodwill
Plastics [Member]
Gross Balance		19,302,000
Accumulated Impairments
Balance	19,302,000	$ 19,302,000
Adjustments to Goodwill

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Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Amortizable Intangible Assets:
Gross Carrying Amount	$ 23,235	$ 23,235
Accumulated Amortization	9,815	9,470
Net Carrying Amount	13,420	13,765
Customer Relationships [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	9,277	8,994
Net Carrying Amount	$ 13,214	$ 13,497
Customer Relationships [Member] | Minimum [Member]
Amortizable Intangible Assets:
Remaining Amortization Periods (Month)	1 year 270 days	2 years
Customer Relationships [Member] | Maximum [Member]
Amortizable Intangible Assets:
Remaining Amortization Periods (Month)	17 years 150 days	17 years 240 days
Covenant Not to Compete [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	$ 590	$ 590
Accumulated Amortization	508	459
Net Carrying Amount	$ 82	$ 131
Remaining Amortization Periods (Month)	150 days	240 days
Other Intangible Assets [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	30	17
Net Carrying Amount	$ 124	$ 137
Remaining Amortization Periods (Month)	2 years 150 days	2 years 240 days

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Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Amortization Expense – Intangible Assets	$ 345	$ 332

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Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Mar. 31, 2018 USD ($)
2018	$ 1,315
2019	1,184
2020	1,133
2021	1,099
2022	$ 1,099

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Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Mar. 31, 2017
Transactions Related to Capital Additions not Settled in Cash	$ 10,451	$ 10,811

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Note 2 - Segment Information (Details Textual)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Number of Reportable Segments	3
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Electric [Member]
Number of Customers			1
Concentration Risk, Percentage			11.70%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member]
Number of Customers			1
Concentration Risk, Percentage			24.30%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member]
Number of Customers			1
Concentration Risk, Percentage			12.00%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member]
Number of Customers			2
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer One [Member]
Concentration Risk, Percentage			20.60%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer Two [Member]
Concentration Risk, Percentage			17.80%
Sales Revenue, Net [Member] | UNITED STATES
Concentration Risk, Percentage	98.30%	98.40%

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Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Electric Sales	$ 241,266	$ 214,117
Interest charges	7,372	7,462
Income Taxes	3,794	6,363
Net Income (Loss)	26,215	19,585
Assets	2,007,418		$ 2,004,278
Discontinued Operations [Member]
Net Income (Loss)		56
Operating Segments [Member] | Electric [Member]
Revenue from Contracts with Customers	13,645	12,469
Regulated operating revenues	122,965	118,551
Interest charges	6,390	6,386
Income Taxes	2,098	6,062
Net Income (Loss)	16,668	15,560
Assets	1,686,255		1,690,224
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	109,180	106,454
Changes in Accrued ARP Revenues	(875)	(1,239)
Regulated operating revenues	108,305	105,215
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	1,015	867
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	68,662	58,417
Interest charges	554	554
Income Taxes	1,223	1,055
Net Income (Loss)	4,164	2,172
Assets	180,319		167,023
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	56,927	48,078
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	10,235	9,552
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	1,500	787
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	49,653	37,157
Interest charges	150	153
Income Taxes	2,414	1,390
Net Income (Loss)	6,844	2,437
Assets	97,953		87,230
Corporate and Eliminations [Member]
Interest charges	278	369
Income Taxes	(1,941)	(2,144)
Net Income (Loss)	(1,461)	(640)
Assets	42,891		$ 59,801
Intersegment Eliminations [Member]
Regulated operating revenues	$ (14)	$ (8)

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Note 3 - Rate and Regulatory Matters (Details Textual)												1 Months Ended		3 Months Ended	12 Months Ended
	Apr. 20, 2018 USD ($)	Mar. 23, 2018 USD ($)	Mar. 22, 2018 USD ($)	Dec. 20, 2017 USD ($)	Nov. 17, 2017 USD ($)	Sep. 28, 2016	May 25, 2016	Feb. 12, 2015	Nov. 06, 2014	Nov. 12, 2013	Jun. 01, 2011 USD ($)	Jun. 30, 2016	Dec. 22, 2015	Mar. 31, 2018 USD ($)	Dec. 31, 2018	Dec. 31, 2017 USD ($)	Mar. 01, 2018 USD ($)	Nov. 02, 2017 USD ($)	Oct. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Apr. 16, 2016	Apr. 15, 2016	Nov. 25, 2009 USD ($)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent																35.00%
Regulatory Liabilities, Total														$ 238,398,000		$ 242,581,000
Minnesota [Member]
Accrued Refund Liabilities Resulting from Tax Rate Reduction														1,900,000
NORTH DAKOTA
Accrued Refund Liabilities Resulting from Tax Rate Reduction														800,000
South Dakota [Member]
Accrued Refund Liabilities Resulting from Tax Rate Reduction														500,000
Scenario, Forecast [Member]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent															21.00%
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Current Return on Equity Used in Transmission Rates						10.32%				12.38%			10.32%
Proposed Reduced Return on Equity Used in Transmission Rates								8.67%		9.15%		9.70%
Additional Incentive Basis Point									0.50%
Expected Percentage of Return on Equity						10.82%
Regulatory Liabilities, Total														$ 1,600,000						$ 2,700,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]
Estimated Interim Rate Refund					$ 9,000,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																					7.5056%	8.61%
Percentage of Allowed Rate of Return on Equity																					9.41%	10.74%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Environmental Cost Recovery Rider [Member] | The 2016 General Rate Case [Member]
Revenues Collected Under Riders, Subject to Customer Refund																			$ 900,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member] | The 2016 General Rate Case [Member]
Revenues Collected Under Riders, Subject to Customer Refund																			$ 1,400,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | ECR and TCR Riders [Member] | The 2016 General Rate Case [Member]
Revenues Collected Under Riders, Subject to Refund, Period of Refund														1 year
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member]
Utility Incentive Percentage in Next Rolling Twelve Months							13.50%
Utility Incentive Percentage in Next Rolling Year Two							12.00%
Utility Incentive Percentage in Next Rolling Year Three							10.00%
Assumed Savings of Utility							1.70%
Financial Incentive, Maximum Percentage of Spending, Year One							40.00%
Financial Incentive, Maximum Percentage of Spending, Year Two							35.00%
Financial Incentive, Maximum Percentage of Spending, Year Three							30.00%
Financial Incentives Recognized During Period																$ 2,600,000
Percentage Decrease in Energy Savings																10.00%
Amount Of Financial Incentive Requested																$ 2,600,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																		7.97%					8.62%
Percentage of Allowed Rate of Return on Equity																		10.30%					10.75%
General Rate Revenue Increase Requested																		$ 13,100,000					$ 3,600,000
Percentage of Increase in Base Rate Revenue Requested																		8.72%					3.00%
Public Utilities, Interim Rate Increase (Decrease), Amount				$ 12,800,000
Public Utilities, Interim Rate Requirement, Decrease in Amount																	$ 4,500,000
Public Utilities, Interim Rate Requirement, Amount																	$ 8,300,000
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 7,100,000	$ 13,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		4.80%
General Rate Revenue Increase Requested, Decrease		$ 6,000,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform		4,800,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform		$ 1,200,000
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member]
Public Utilities General Rate Revenue Increase Approved											$ 643,000
Percentage of Increase in Base Rate Revenue Approved											2.32%
Public Utilities Allowed Rate of Return on Rate Base Subsequent to Approval of Increase in Base Rate											8.50%
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member] | Subsequent Event [Member]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 3,300,000
Increase in Annual Non-fuel Rates Requested, Step One, Percentage	10.10%
Increase in Annual Non-fuel Rates Requested, Step Two, Percentage	1.70%
Otter Tail Power Company [Member] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member]
Expanded Capacity of Projects														345
Extended Distance of Transmission Line														163
Current Projected Cost														$ 96,500,000
Percentage of Assets of Project														100.00%
Otter Tail Power Company [Member] | Big Stone South - Brookings MVP [Member]
Expanded Capacity of Projects														345
Extended Distance of Transmission Line														70
Current Projected Cost														$ 72,400,000
Percentage of Assets of Project														100.00%

XML

Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Revenues recorded under rate riders		$ 10,116	$ 15,007
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	[1]	2,516	1,966
Minnesota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders			2,170
Revenues recorded under rate riders		(29)
Minnesota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders			2,824
Revenues recorded under rate riders		(31)
Minnesota [Member] | Renewable Resource Cost Recovery Rider [Member]
Revenues recorded under rate riders		525
North Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		2,062	2,511
North Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,821	2,488
North Dakota [Member] | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		1,967	1,770
South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders		229	240
South Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		536	441
South Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		$ 520	$ 597

[1] Includes MNCIP costs recovered in base rates.

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Note 3 - Rate and Regulatory Matters - Summary of Status of Updates for Previous Two Years for Various Rate Riders (Details) - Otter Tail Power Company [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($) kWh
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
R - Request Date	Mar. 31, 2018
Effective Date Requested or Approved	Oct. 01, 2018
Annual Revenue	$ 10,400
Rate rider rate (Kilowatt-Hour) | kWh	0.006
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Oct. 01, 2017
Annual Revenue	$ 9,868
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
A - Approval Date	Sep. 15, 2017
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2015 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Oct. 01, 2016
Annual Revenue	$ 8,590
Rate rider rate (Kilowatt-Hour) | kWh	0.00275
A - Approval Date	Jul. 19, 2016
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Nov. 01, 2017	[1]
Annual Revenue	$ (3,311)	[1]
A - Approval Date	Oct. 30, 2017	[1]
Rate	Various	[1]
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Sep. 01, 2016
Annual Revenue	$ 4,736
A - Approval Date	Jul. 05, 2016
Rate	Various
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Apr. 01, 2016
Annual Revenue	$ 7,203
A - Approval Date	Mar. 09, 2016
Rate	Various
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Nov. 01, 2017
Annual Revenue	$ (1,943)
A - Approval Date	Oct. 30, 2017
Rate of base	(0.935%)
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Sep. 01, 2016
Annual Revenue	$ 11,884
A - Approval Date	Jul. 05, 2016
Rate of base	6.927%
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Nov. 01, 2017
Annual Revenue	$ 1,279
Rate rider rate (Kilowatt-Hour) | kWh	0.00049
A - Approval Date	Oct. 30, 2017
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Jan. 01, 2017
Annual Revenue	$ 6,916
A - Approval Date	Dec. 14, 2016
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 01, 2018
Annual Revenue	$ 7,469
A - Approval Date	Feb. 27, 2018
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Jan. 01, 2018
Annual Revenue	$ 7,959
A - Approval Date	Nov. 29, 2017
Rate	Various
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Jan. 01, 2018
Annual Revenue	$ 8,537
A - Approval Date	Dec. 20, 2017
Rate of base	6.629%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Jul. 01, 2016
Annual Revenue	$ 10,359
A - Approval Date	Jun. 22, 2016
Rate of base	7.904%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 01, 2018
Annual Revenue	$ 7,718
A - Approval Date	Feb. 27, 2018
Rate of base	5.593%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Aug. 01, 2017
Annual Revenue	$ 9,917
A - Approval Date	Jul. 12, 2017
Rate of base	7.633%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Jan. 01, 2018
Annual Revenue	$ 9,989
A - Approval Date	Dec. 20, 2017
Rate of base	7.756%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Apr. 01, 2017
Annual Revenue	$ 9,156
A - Approval Date	Mar. 15, 2017
Rate of base	7.005%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Jul. 01, 2016
Annual Revenue	$ 9,262
A - Approval Date	Jun. 22, 2016
Rate of base	7.573%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 01, 2018
Annual Revenue	$ 9,650
A - Approval Date	Feb. 27, 2018
Rate of base	7.493%
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Mar. 01, 2017
Annual Revenue	$ 2,053
A - Approval Date	Feb. 17, 2017
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Mar. 01, 2016
Annual Revenue	$ 1,895
A - Approval Date	Feb. 12, 2016
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Mar. 01, 2018
Annual Revenue	$ 1,779
A - Approval Date	Feb. 28, 2018
Rate	Various
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Nov. 01, 2016
Annual Revenue	$ 2,238
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
A - Approval Date	Oct. 26, 2016
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Nov. 01, 2017
Annual Revenue	$ 2,082
Rate rider rate (Kilowatt-Hour) | kWh	0.00483
A - Approval Date	Oct. 13, 2017

[1] Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

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Note 4 - Regulatory Assets and Liabilities (Details Textual)	3 Months Ended
	Mar. 31, 2018
Regulatory Noncurrent Asset, Remaining Recovery Period	14 years 180 days

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Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
		Mar. 31, 2018	Dec. 31, 2017
Regulatory Assets - Current		$ 19,736	$ 22,551
Regulatory Assets - Long -Term		125,667	129,576
Regulatory Assets - Total		$ 145,403	$ 152,127
Regulatory Assets - Remaining Recovery/Refund Period (Month)
Regulatory Liabilities - Current		$ 5,119	$ 9,688
Regulatory Liabilities - Long -Term		233,279	232,893
Regulatory Liabilities, Total		$ 238,398	$ 242,581
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)
Net Regulatory Asset Position - Current		$ 14,617	$ 12,863
Net Regulatory Asset Position - Long-Term		(107,612)	(103,317)
Net Regulatory Asset/(Liability) Position		(92,995)	(90,454)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		148,938	149,052
Regulatory Liabilities, Total		$ 148,938	$ 149,052
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		84,223	83,100
Regulatory Liabilities, Total		$ 84,223	$ 83,100
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current		$ 2,414	$ 5,778
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 2,414	$ 5,778
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 1,161	$ 1,667
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 1,161	$ 1,667
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		210 days	330 days
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 317	$ 187
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 317	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Renewable Resource Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 371
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 371
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		270 days
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 304	$ 409
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 304	$ 409
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		210 days	1 year
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 351
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 351
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current		$ 68	$ 132
Regulatory Liabilities - Long -Term		36	48
Regulatory Liabilities, Total		$ 104	$ 180
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 270 days	2 years
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 5
Regulatory Liabilities - Long -Term		82	84
Regulatory Liabilities, Total		$ 88	$ 89
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		15 years 270 days	16 years
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 60	$ 151
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 60	$ 151
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Transmission Cost Recovery Rider Accrued Refund [member]
Regulatory Liabilities - Current		$ 37	$ 802
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 37	$ 802
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		210 days	300 days
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current		$ 30	$ 208
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 30	$ 208
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		30 days	120 days
Minnesota Southwest Power Pool Transmission Cost Tracker Refund [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term			609
Regulatory Liabilities, Total			$ 609
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year 300 days
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current			$ 349
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total			$ 349
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 9,090	$ 9,090
Regulatory Assets - Long -Term	[1]	110,214	112,487
Regulatory Assets - Total	[1]	$ 119,304	$ 121,577
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 5,313	$ 7,385
Regulatory Assets - Long -Term	[2]	3,468	2,774
Regulatory Assets - Total	[2]	$ 8,781	$ 10,159
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	2 years 180 days	1 year 270 days
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	6,779	6,651
Regulatory Assets - Total	[1]	$ 6,779	$ 6,651
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 3,463	$ 4,063
Regulatory Assets - Long -Term	[1]	1,989	2,405
Regulatory Assets - Total	[1]	$ 5,452	$ 6,468
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 270 days	3 years
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 657	$ 650
Regulatory Assets - Long -Term	[1]	1,467	1,636
Regulatory Assets - Total	[1]	$ 2,124	$ 2,286
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	3 years 30 days	3 years 120 days
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 246	$ 254
Regulatory Assets - Long -Term	[1]	904	960
Regulatory Assets - Total	[1]	$ 1,150	$ 1,214
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	14 years 180 days	14 years 270 days
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 100	$ 100
Regulatory Assets - Long -Term	[1]	417	442
Regulatory Assets - Total	[1]	$ 517	$ 542
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	5 years 60 days	5 years 150 days
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 374	$ 309
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 374	$ 309
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]	$ 322	$ 75
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 322	$ 75
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	196
Regulatory Assets - Total	[1]	$ 196
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives
North Dakota Renewable Resource Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 206
Regulatory Assets - Long -Term	[2]		236
Regulatory Assets - Total	[2]		$ 442
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year 90 days
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	166
Regulatory Assets - Total	[1]	$ 166
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	67	1,985
Regulatory Assets - Total	[1]	$ 67	$ 1,985
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year 270 days	2 years
North Dakota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 133
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 133
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year 270 days
Minnesota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 38	$ 267
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 38	$ 267
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	30 days	120 days
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 152
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 152
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year

[1] Costs subject to recovery excluding a rate of return.

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

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Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	May 03, 2018	Apr. 30, 2018
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations	$ 0.01	$ 0.01
Dividend Reinvestment and Share Purchase Plan [Member] | Subsequent Event [Member]
Shelf Registration, Shares			1,500,000
Distribution Agreement [Member] | Subsequent Event [Member]
Agreement to Sell Shares, Value				$ 75

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Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Balance, beginning	$ 696,892
Common Stock Issuances, Net of Expenses
Common Stock Retirements	(2,409)
Net Income	26,215	$ 19,585
Other Comprehensive Loss	(502)
Employee Stock Incentive Plans Expense	1,146
Common Dividends ($0.335 per share)	(13,292)
Balance, ending	708,050
Par Value, Common Shares [Member]
Balance, beginning	197,787
Common Stock Issuances, Net of Expenses	638
Common Stock Retirements	(292)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($0.335 per share)
Balance, ending	198,133
Premium on Common Shares [Member]
Balance, beginning	343,450
Common Stock Issuances, Net of Expenses	(638)
Common Stock Retirements	(2,117)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense	1,146
Common Dividends ($0.335 per share)
Balance, ending	341,841
Retained Earnings [Member]
Balance, beginning	161,286
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income	26,215
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($0.335 per share)	(13,292)
Balance, ending	174,209
Accumulated Other Comprehensive Income/(Loss) [Member]
Balance, beginning	(5,631)
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Loss	(502)
Employee Stock Incentive Plans Expense
Common Dividends ($0.335 per share)
Balance, ending	$ (6,133)

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Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32

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Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	3 Months Ended
	Mar. 31, 2018 shares
Common Shares Outstanding, beginning balance (in shares)	39,557,491
Issuances:
Executive Stock Performance Awards (2015 shares earned) (in shares)	114,648
Vesting of Restricted Stock Units (in shares)	12,950
Retirements:
Shares Withheld for Individual Income Tax Requirements (in shares)	(58,495)
Common Shares Outstanding, ending balance (in shares)	39,626,594

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Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Weighted Average Common Shares Outstanding – Basic (in shares)	39,550,874	39,350,802
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 (in shares)	223,162	201,639
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	59,130	57,873
Nonvested Restricted Shares (in shares)	27,643	27,069
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,873	3,342
Total Dilutive Shares (in shares)	312,808	289,923
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,863,682	39,640,725

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Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions		3 Months Ended
	Feb. 05, 2018	Mar. 31, 2018
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Total		$ 5.9
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years 73 days
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	54,000
Period Specified for Average Adjusted Return	3 years
Number of Trading Days	20 days
Number of Shares Authorized for Actual Payment	81,000
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member]
Percentage of Target Amount as Actual Payment	0.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member]
Percentage of Target Amount as Actual Payment	150.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,000
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,000

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Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) - Executive Officer [Member] - The 2014 Stock Incentive Plan [Member]	Feb. 05, 2018 $ / shares shares
Restricted Stock Units (RSUs) [Member]
Shares/units granted (in shares) | shares	15,200
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 41.325
Shares/units granted, vesting date	Feb. 06, 2022
Stock Performance Awards [Member]
Shares/units granted (in shares) | shares	54,000
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 35.73
Shares/units granted, vesting date	Dec. 31, 2020

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Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals)	Feb. 05, 2018
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | Executive Officer [Member]
Shares/units granted, vesting percentage	25.00%

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Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Stock compensation expense	$ 1,146	$ 1,150
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	651	649
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	249	264
Restricted Stock Units (RSUs) [Member] | Non-executive Employees [Member]
Stock compensation expense	64	87
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense	16	22
Restricted Stock [Member] | Directors [Member]
Stock compensation expense	$ 166	$ 128

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Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($)	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Capitalization, Long-term Debt and Equity, Total	$ 1,297,993,000	$ 1,187,272,000
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio	51.60%
Net Assets Restricted from Distribution	$ 481,000,000
Capitalization, Long-term Debt and Equity, Total	$ 1,178,024,000
Otter Tail Power Company [Member] | Minimum [Member]
Equity to Total Capitalization Ratio	47.40%
Otter Tail Power Company [Member] | Maximum [Member]
Equity to Total Capitalization Ratio	58.00%

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Note 8 - Commitments and Contingencies (Details Textual)	3 Months Ended	12 Months Ended
	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Loss Contingency, Estimate of Possible Loss	$ 1,000,000
Agreement to Lease Rail Cars for Transporting Coal to Hoot Lake Plant [Member]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	243,000
Operating Leases, Future Minimum Payments, Due in Two Years	324,000
Operating Leases, Future Minimum Payments, Due in Three Years	324,000
Operating Leases, Future Minimum Payments, Due in Four Years	$ 135,000
Otter Tail Power Company [Member]
Number of Utilities Participating in MISO RSG Proceeding Before FERC	200
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1,600,000
Otter Tail Power Company [Member] | Coal Purchase Commitments 1 [Member]
Contract Expiration Year	2041
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2019
Otter Tail Power Company [Member] | Construction Programs [Member]
Contract Expiration Year	2019	2019
Long-term Purchase Commitment, Amount	$ 37,500,000	$ 41,000,000
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2040
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount	$ 6,200,000	$ 6,700,000

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Note 9 - Short-term and Long-term Borrowings (Details Textual) $ in Billions	Feb. 07, 2018 USD ($)
The 2018 Note Purchase Agreement [Member]
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount	10.00%
Debt Instrument, Prepayment, Percentage of the Principal Amount Prepaid	100.00%
Debt Instrument, Percentage of Principal Amount to be Offered for Prepayment in the Event of a Change of Control	100.00%
Otter Tail Power Company [Member] | Series 2018 A senior Unsecured Notes Due February 7, 2048 [Member]
Debt Instrument, Face Amount	$ 0.1
Debt Instrument, Interest Rate, Stated Percentage	4.07%

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Note 9 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Line Limit	$ 300,000
In Use	30,319
Restricted due to Outstanding Letters of Credit	300
Available	269,381	$ 187,239
Otter Tail Corporation Credit Agreement [Member]
Line Limit	130,000
In Use	6,182
Restricted due to Outstanding Letters of Credit
Available	123,818	130,000
OTP Credit Agreement [Member]
Line Limit	170,000
In Use	24,137
Restricted due to Outstanding Letters of Credit	300
Available	$ 145,563	$ 57,239

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Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Short-Term Debt	$ 30,319	$ 112,371
Long-Term Debt	592,651	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	171	186
Unamortized Long-Term Debt Issuance Costs	2,537	2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	589,943	490,380
Total Short-Term and Long-Term Debt (with current maturities)	620,433	602,937
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt	7	27
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	644	684
Otter Tail Power Company [Member]
Short-Term Debt	24,137	112,371
Long-Term Debt	512,000	412,000
Less: Current Maturities net of Unamortized Debt Issuance Costs
Unamortized Long-Term Debt Issuance Costs	2,091	1,684
Total Long-Term Debt net of Unamortized Debt Issuance Costs	509,909	410,316
Total Short-Term and Long-Term Debt (with current maturities)	534,046	522,687
Otter Tail Power Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt
Otter Tail Power Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000
Otter Tail Power Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt
Parent Company [Member]
Short-Term Debt	6,182
Long-Term Debt	80,651	80,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	171	186
Unamortized Long-Term Debt Issuance Costs	446	461
Total Long-Term Debt net of Unamortized Debt Issuance Costs	80,034	80,064
Total Short-Term and Long-Term Debt (with current maturities)	86,387	80,250
Parent Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Parent Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt
Parent Company [Member] | North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt	7	27
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 644	$ 684

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Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage		0.90%
Long-Term Debt, Due Date		Feb. 05, 2018
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.07%
Long-Term Debt, Due Date	Feb. 07, 2048
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Debt Instrument, Interest Rate, Stated Percentage	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018	Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

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Note 10 - Pension Plan and Other Postretirement Benefits (Details Textual) - Pension Plan [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Minimum Funding Requirement		$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 20,000

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Note 10 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,615	$ 1,407
Interest Cost on Projected Benefit Obligation		3,363	3,534
Expected Return on Assets		(5,300)	(4,807)
Amortization of Prior-Service Cost:
From Regulatory Asset		4	30
From Other Comprehensive Income	[1]		1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,784	1,273
From Other Comprehensive Income	[1]	44	31
Net Periodic Pension Cost	[2]	1,510	1,469
Service Cost—Benefit Earned During the Period		1,615	1,407
Interest Cost on Projected Benefit Obligation		3,363	3,534
From Other Comprehensive Income	[1]	44	31
From Regulatory Asset		4	30
From Other Comprehensive Income	[1]		1
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		328	285
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		1,247	1,100
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		40	34
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		(21)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		(84)	50
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		100	73
Interest Cost on Projected Benefit Obligation		399	422
Amortization of Prior-Service Cost:
From Regulatory Asset		4	4
From Other Comprehensive Income	[3]	10	9
Amortization of Net Actuarial Loss:
From Regulatory Asset		67	71
From Other Comprehensive Income	[3]	165	110
Net Periodic Pension Cost	[4]	745	689
Service Cost—Benefit Earned During the Period		100	73
Interest Cost on Projected Benefit Obligation		399	422
From Other Comprehensive Income	[3]	165	110
From Regulatory Asset		4	4
From Other Comprehensive Income	[3]	10	9
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		25	24
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		75	49
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		645	616
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		382	356
Interest Cost on Projected Benefit Obligation		645	678
Amortization of Prior-Service Cost:
From Regulatory Asset		412	233
From Other Comprehensive Income	[1]	10	6
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost	[5]	1,449	1,273
Service Cost—Benefit Earned During the Period		382	356
Interest Cost on Projected Benefit Obligation		645	678
From Regulatory Asset		412	233
From Other Comprehensive Income	[1]	10	6
Effect of Medicare Part D Subsidy		(37)	(140)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		78	247
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		294	278
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		10	9
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		217
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Amortization of Net Actuarial Loss:
Net Periodic Pension Cost		$ 850	$ 739

[1] Corporate cost included in nonservice cost components of postretirement benefits.

[2] Allocation of Costs: Costs included in OTP capital expenditures $ 328 $ 285 Service costs included in electric operation and maintenance expenses 1,247 1,100 Service costs included in other nonelectric expenses 40 34 Nonservice costs capitalized as regulatory assets (21 ) -- Nonservice costs included in nonservice cost components of postretirement benefits (84 ) 50

[3] Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company's consolidated statements of income.

[4] Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 24 Service costs included in other nonelectric expenses 75 49 Nonservice costs included in nonservice cost components of postretirement benefits 645 616

[5] Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 247 Service costs included in electric operation and maintenance expenses 294 278 Service costs included in other nonelectric expenses 10 9 Nonservice costs capitalized as regulatory assets 217 -- Nonservice costs included in nonservice cost components of postretirement benefits 850 739

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Note 11 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Otter Tail Corporation Credit Agreement [Member]
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR
Debt Instrument, Basis Spread on Variable Rate	1.50%	1.50%
OTP Credit Agreement [Member]
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR
Debt Instrument, Basis Spread on Variable Rate	1.25%	1.25%

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Note 11 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 1,121	$ 16,216
Short-Term Debt	(30,319)	(112,371)
Long-Term Debt including Current Maturities	(590,114)	(490,566)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	1,121	16,216
Short-Term Debt	(30,319)	(112,371)
Long-Term Debt including Current Maturities	$ (614,873)	$ (543,691)

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Note 13 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($)
Period for Unrecognized Tax Benefits Not Expected Change	1 year
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ 0

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Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Before Income Taxes – Continuing Operations	$ 30,009	$ 25,892
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017)	7,802	10,098
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(1,120)	(2,052)
Property Related Differences and Other Regulatory Adjustments	(1,073)	105
Excess Tax Deduction – Equity Method Stock Awards	(624)	(697)
Other Comprehensive Income Deferred Tax Rate Adjustment	(531)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(212)
Research and Development and Other Tax Credits	(180)	(157)
Allowance for Funds Used During Construction – Equity	(167)	(67)
Corporate Owned Life Insurance	(8)	(294)
Section 199 Domestic Production Activities Deduction		(330)
Other Items – Net	(47)	(31)
Income Tax Expense – Continuing Operations	$ 3,794	$ 6,363
Effective Income Tax Rate – Continuing Operations	12.60%	24.60%

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Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Composite Federal and State Statutory Rate	26.00%	39.00%

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Note 13 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Balance, beginning	$ 684	$ 891
Decreases Related to Tax Positions for Prior Years	(44)
Increases Related to Tax Positions for Current Year	36	43
Uncertain Positions Resolved During Year
Balance, ending	$ 676	$ 934