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, 2019

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)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Shares, par value $5.00 per share	OTTR	The Nasdaq Stock Market LLC

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 every Interactive Data File required to be submitted 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 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 ☐

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, 2019 – 39,754,652 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – March 31, 2019 and December 31, 2018 (not audited)	2 & 3
	Consolidated Statements of Income – Three Months Ended March 31, 2019 and 2018 (not audited)	4
	Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2019 and 2018 (not audited)	5
	Consolidated Statements of Common Shareholders’ Equity – Three Months Ended March 31, 2019 and 2018 (not audited)	6
	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2019 and 2018 (not audited)	7
	Condensed Notes to Consolidated Financial Statements (not audited)	8-34
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35-47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47-48
Item 4.	Controls and Procedures	48
Part II. Other Information
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 6.	Exhibits	49
Signatures		49

1

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation
Consolidated Balance Sheets
(not audited)
(in thousands)	March 31, 2019		December 31, 2018
Assets
Current Assets
Cash and Cash Equivalents	$	891	$	861
Accounts Receivable:
Trade—Net		113,144		75,144
Other		8,827		9,741
Inventories		106,732		106,270
Unbilled Receivables		18,928		23,626
Income Taxes Receivable		--		2,439
Regulatory Assets		15,193		17,225
Other		9,986		6,114
Total Current Assets		273,701		241,420
Investments		9,220		8,961
Other Assets		38,653		35,759
Goodwill		37,572		37,572
Other Intangibles—Net		12,154		12,450
Regulatory Assets		133,427		135,257
Right of Use Assets - Operating Leases		20,712		--
Plant
Electric Plant in Service		2,160,321		2,019,721
Nonelectric Operations		231,135		228,120
Construction Work in Progress		49,054		181,626
Total Gross Plant		2,440,510		2,429,467
Less Accumulated Depreciation and Amortization		861,401		848,369
Net Plant		1,579,109		1,581,098
Total Assets	$	2,104,548	$	2,052,517

See accompanying condensed notes to consolidated financial statements.

2

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands, except share data)	March 31, 2019			December 31, 2018
Liabilities and Equity
Current Liabilities
Short-Term Debt	$	43,601		$	18,599
Current Maturities of Long-Term Debt		174			172
Accounts Payable		100,496			96,291
Accrued Salaries and Wages		15,139			24,857
Accrued Federal and State Income Taxes		2,459			--
Other Accrued Taxes		18,590			17,287
Regulatory Liabilities		7,787			738
Current Operating Lease Liabilities		3,900			--
Other Accrued Liabilities		8,575			12,149
Total Current Liabilities		200,721			170,093
Pensions Benefit Liability		88,223			98,358
Other Postretirement Benefits Liability		72,456			71,561
Long-Term Operating Lease Liabilities		17,160			--
Other Noncurrent Liabilities		26,354			24,326
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		121,863			120,976
Deferred Tax Credits		19,637			19,974
Regulatory Liabilities		225,496			226,469
Other		2,117			1,895
Total Deferred Credits		369,113			369,314
Capitalization
Long-Term Debt—Net		590,022			590,002
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, 2019—39,729,708 Shares; 2018—39,664,884 Shares		198,649			198,324
Premium on Common Shares		342,991			344,250
Retained Earnings		203,619			190,433
Accumulated Other Comprehensive Loss		(4,760	)		(4,144	)
Total Common Equity		740,499			728,863
Total Capitalization		1,330,521			1,318,865
Total Liabilities and Equity	$	2,104,548		$	2,052,517

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)	2019			2018
Operating Revenues
Electric:
Revenues from Contracts with Customers	$	129,144		$	123,825
Changes in Accrued Revenues under Alternative Revenue Programs		(1,049	)		(875	)
Total Electric Revenues		128,095			122,950
Product Sales under Contracts with Customers		117,877			118,316
Total Operating Revenues		245,972			241,266
Operating Expenses
Production Fuel – Electric		18,920			18,706
Purchased Power – Electric System Use		21,952			21,593
Electric Operation and Maintenance Expenses		38,382			39,475
Cost of Products Sold (depreciation included below)		90,582			88,785
Other Nonelectric Expenses		13,477			12,494
Depreciation and Amortization		19,131			18,763
Property Taxes – Electric		3,959			3,835
Total Operating Expenses		206,403			203,651
Operating Income		39,569			37,615
Interest Charges		7,826			7,372
Nonservice Cost Components of Postretirement Benefits		1,035			1,417
Other Income		1,244			1,183
Income Before Income Taxes		31,952			30,009
Income Tax Expense		5,628			3,794
Net Income	$	26,324		$	26,215
Average Number of Common Shares Outstanding—Basic		39,657,321			39,550,874
Average Number of Common Shares Outstanding—Diluted		39,903,165			39,863,682
Basic Earnings Per Common Share	$	0.66		$	0.66
Diluted Earnings Per Common Share	$	0.66		$	0.66

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)	2019			2018
Net Income	$	26,324		$	26,215
Other Comprehensive Income (Loss):
Unrealized Gains (Losses) on Available-for-Sale Securities:
Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period		--			(110	)
Unrealized Gains (Losses) Arising During Period		91			(66	)
Income Tax (Expense) Benefit		(19	)		37
Change in Unrealized Losses/Gains on Available-for-Sale Securities – net-of-tax		72			(139	)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		130			227
Income Tax Expense		(34	)		(59	)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act		--			(531	)
Pension and Postretirement Benefit Plans – net-of-tax		96			(363	)
Total Other Comprehensive Income (Loss)		168			(502	)
Total Comprehensive Income	$	26,492		$	25,713

See accompanying condensed notes to consolidated financial statements.

5

Otter Tail Corporation

Consolidated Statements of Common Shareholders’ Equity

For the Three-Month Periods Ended March 31, 2019 and 2018

(not audited)

(in thousands, except common shares outstanding)	Common Shares Outstanding			Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 2018		39,664,884		$	198,324		$	344,250		$	190,433		$	(4,144	)	$	728,863
Common Stock Issuances, Net of Expenses		120,048			601			(601	)								--
Common Stock Retirements		(55,224	)		(276	)		(2,454	)								(2,730	)
Net Income											26,324						26,324
Other Comprehensive Income														168			168
ASU 2018-02 2017 TCJA Stranded Tax Transfer											784			(784	)		--
Employee Stock Incentive Plan Expense								1,796									1,796
Common Dividends ($0.35 per share)											(13,922	)					(13,922	)
Balance, March 31, 2019		39,729,708		$	198,649			342,991		$	203,619		$	(4,760	)	$	740,499
Balance, December 31, 2017		39,557,491		$	197,787		$	343,450		$	161,286		$	(5,631	)	$	696,892
Common Stock Issuances, Net of Expenses		127,598			638			(638	)								--
Common Stock Retirements		(58,495	)		(292	)		(2,117	)								(2,409	)
Net Income											26,215						26,215
Other Comprehensive Loss														(502	)		(502	)
Employee Stock Incentive Plan Expense								1,146									1,146
Common Dividends ($0.335 per share)											(13,292	)					(13,292	)
Balance, March 31, 2018		39,626,594		$	198,133			341,841		$	174,209		$	(6,133	)	$	708,050

6

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Three Months Ended March 31,
(in thousands)	2019			2018
Cash Flows from Operating Activities
Net Income	$	26,324		$	26,215
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization		19,131			18,763
Deferred Tax Credits		(337	)		(354	)
Deferred Income Taxes		835			2,901
Change in Deferred Debits and Other Assets		1,464			6,295
Discretionary Contribution to Pension Plan		(10,000	)		(20,000	)
Change in Noncurrent Liabilities and Deferred Credits		8,787			(5,091	)
Allowance for Equity/Other Funds Used During Construction		(330	)		(638	)
Stock Compensation Expense—Equity Awards		1,796			1,146
Other—Net		375			(284	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(37,086	)		(25,047	)
Change in Inventories		(462	)		35
Change in Other Current Assets		128			2,334
Change in Payables and Other Current Liabilities		4,088			(2,798	)
Change in Interest and Income Taxes Receivable/Payable		2,437			1,163
Net Cash Provided by Operating Activities		17,150			4,640
Cash Flows from Investing Activities
Capital Expenditures		(24,687	)		(23,618	)
Net Proceeds from Disposal of Noncurrent Assets		509			510
Cash Used for Investments and Other Assets		(1,258	)		(719	)
Net Cash Used in Investing Activities		(25,436	)		(23,827	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		8			2,338
Net Short-Term Borrowings (Repayments)		25,002			(82,052	)
Payments for Retirement of Capital Stock		(2,730	)		(2,409	)
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		(42	)		(60	)
Dividends Paid		(13,922	)		(13,292	)
Net Cash Provided by Financing Activities		8,316			4,092
Net Change in Cash and Cash Equivalents		30			(15,095	)
Cash and Cash Equivalents at Beginning of Period		861			16,216
Cash and Cash Equivalents at End of Period	$	891		$	1,121

See accompanying condensed notes to consolidated financial statements.

7

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, 2018. Because of seasonal and other factors, the earnings for the three months ended March 31, 2019 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, 2018.

1. Summary of Significant Accounting Policies

Revenue Recognition

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. 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606), the Company also records adjustments to Electric segment revenues for amounts subject to future collection 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 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). These revenues account for over 80% of other electric revenues reported in the table of disaggregated revenues in note 2. 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.

8

OTP has recovered costs and earned 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 riders.

● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) 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 net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery 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, 2019, and 2018.

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 customer 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. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. 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. 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 for a disaggregation of the Company’s revenues by business segment for the three-month periods ended March 31, 2019 and 2018.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The 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.

9

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, 2019 and December 31, 2018:

March 31, 2019 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,444
Corporate Debt Securities – Held by Captive Insurance Company			$	5,975
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,644
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		1,396
Total Assets	$	2,840	$	7,619

December 31, 2018 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,294
Corporate Debt Securities – Held by Captive Insurance Company			$	5,898
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,586
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		838
Total Assets	$	2,132	$	7,484

The level 2 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company 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, 2019 could be as high as $53.1 million, OTP’s 35% share of unrecovered costs.

10

Inventories

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

	March 31,		December 31,
(in thousands)	2019		2018
Finished Goods	$	35,771	$	37,130
Work in Process		20,503		20,393
Raw Material, Fuel and Supplies		50,458		48,747
Total Inventories	$	106,732	$	106,270

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 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 2019:

(in thousands)	Gross Balance December 31, 2018		Accumulated Impairments		Balance (net of impairments) December 31, 2018		Adjustments to Goodwill in 2019		Balance (net of impairments) March 31, 2019
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, 2019 and December 31, 2018:

March 31, 2019 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,410	$	12,081	9	-	197
Other		154		81		73		17
Total	$	22,645	$	10,491	$	12,154

December 31, 2018 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,127	$	12,364	12	-	200
Other		154		68		86		20
Total	$	22,645	$	10,195	$	12,450

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Amortization Expense – Intangible Assets	$	296	$	345

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

(in thousands)	2019		2020		2021		2022		2023
Estimated Amortization Expense – Intangible Assets	$	1,184	$	1,133	$	1,099	$	1,099	$	1,099

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Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2019		2018
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	4,338	$	10,451

New Accounting Standards Adopted

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 supersedes the requirements under ASC Topic 840 on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. 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. The Company adopted the amendments in ASU 2016-02 to its consolidated financial statements effective January 1, 2019. See note 8 for further information on leases and the Company’s elections for applying the new standard.

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/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the 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. 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 adopted the updates in ASU 2018-02 effective January 1, 2019, applying them in the period of adoption and not retrospectively. On adoption, the Company reclassified $784,000 of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates.

Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below.

(in thousands)	Unrealized Gains on Available-for- Sale Securities		Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits			AOCI/(L)
Balance on December 22, 2017 – Pre-tax	$	71	$	(5,672	)	$	(5,601	)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$	10	$	(794	)	$	(784	)

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.

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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. The Company early adopted the amendments in ASU 2017-04 in the first quarter of 2019. The Company had no indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had no impact on the Company’s consolidated financial statements.

2. 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 maker. 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, material handling components and extruded raw material stock. 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. 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.

While no single customer accounted for over 10% of the Company’s consolidated revenue in 2018, certain customers provided a significant portion of each business segment’s 2018 revenue. The Electric segment has one customer that provided 11.2% of 2018 segment revenues. The Manufacturing segment has one customer that manufactures and sells recreational vehicles that provided 22.2% of 2018 segment revenues and one customer that manufactures and sells lawn and garden equipment that provided 11.2% of 2018 segment revenues. The Manufacturing segment’s top five revenue-generating customers provided over 52% of 2018 segment revenues. The Plastics segment has two customers that together provided 39.1% of 2018 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 99.0% and 98.3% of its operating revenues for the respective three-month periods ended March 31, 2019 and 2018 came from sales within the United States.

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The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three months ended March 31, 2019 and 2018 and total assets by business segment as of March 31, 2019 and December 31, 2018 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	114,955		$	109,180
Changes in Accrued ARP Revenues		(1,049	)		(875	)
Total Retail Sales Revenue		113,906			108,305
Transmission Services Revenue		10,862			11,903
Wholesale Revenues – Company Generation		1,527			1,015
Other Revenues		1,814			1,742
Total Electric Segment Revenues		128,109			122,965
Manufacturing Segment:
Metal Parts and Tooling		66,724			56,927
Plastic Products and Tooling		9,045			10,235
Other		2,053			1,500
Total Manufacturing Segment Revenues		77,822			68,662
Plastics Segment – Sale of PVC Pipe Products		40,058			49,653
Intersegment Eliminations		(17	)		(14	)
Total	$	245,972		$	241,266

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Electric	$	6,641	$	6,390
Manufacturing		584		554
Plastics		149		150
Corporate and Intersegment Eliminations		452		278
Total	$	7,826	$	7,372

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	4,771		$	2,098
Manufacturing		1,454			1,223
Plastics		1,329			2,414
Corporate		(1,926	)		(1,941	)
Total	$	5,628		$	3,794

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	18,700		$	16,668
Manufacturing		4,842			4,164
Plastics		3,729			6,844
Corporate		(947	)		(1,461	)
Total	$	26,324		$	26,215

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Identifiable Assets

	March 31,		December 31,
(in thousands)	2019		2018
Electric	$	1,737,278	$	1,728,534
Manufacturing		217,390		187,556
Plastics		104,544		91,630
Corporate		45,336		44,797
Total	$	2,104,548	$	2,052,517

3. Rate and Regulatory Matters

Below are descriptions of OTP’s major capital expenditure projects that have had, or are expected to 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 2019 and 2018.

Major Capital Expenditure Projects

Astoria Station—OTP is constructing this 245-megawatt (MW) simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota 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. A final order granting an Advance Determination of Prudence (ADP) for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. As of March 31, 2019, OTP had capitalized approximately $7.7 million in development and other costs associated with Astoria Station.

Merricourt Project—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 and certain specified liabilities associated with a 150-MW wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement will close on satisfaction of various closing conditions (including regulatory approvals). Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF pursuant to which EDF will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $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 customary representations, warranties, covenants and indemnities for this type of transaction. 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, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on January 10, 2018. A final order for an ADP, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. The Merricourt generation interconnection agreement with MISO was approved by the FERC in April 2019. Construction of the Merricourt Project will begin after closing on the Purchase Agreement, anticipated to occur in the last half of 2019. As of March 31, 2019, OTP had capitalized approximately $5.3 million in development costs associated with the Merricourt Project.

Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This 345-kilovolt transmission line, energized on February 6, 2019, extends 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., and the parties have equal ownership interest in the transmission line portion of the project. The 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 MISO 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. OTP’s capitalized costs on this project as of March 31, 2019 were approximately $106 million, which includes assets that are 100% owned by OTP.

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Recovery of OTP’s major transmission investments is through the MISO Tariff and, currently, Minnesota, North Dakota and South Dakota base rates and 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 is 8.61% and its allowed rate of return on equity (ROE) is 10.74%.

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 (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

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 changes to the MNCIP financial incentive. The model included incentives for utilities 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 was also limited to 40% of 2017 MNCIP spending and 35% of 2018 spending and will be limited to 30% of 2019 spending. The new model reduces the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. The Minnesota Department of Commerce (MNDOC) issued a proposed decision on March 20, 2019 to extend all utilities 2017-2019 CIP plans one year, through 2020.

 

On April 1, 2019 OTP filed a request for approval of its 2018 energy savings, recovery of $3.0 million in accrued financial incentives and recovery of 2018 program costs not included in base rates.

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 MVPs 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 diverted 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 resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision would 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 June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. Oral arguments were heard by the Minnesota Supreme Court on March 11, 2019.

On November 30, 2018 OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing two scenarios were submitted based on whether the Minnesota Supreme Court affirms the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturns the Minnesota Court of Appeals decision and includes the two MVP projects in the TCR rider. Action by the Minnesota Supreme Court is expected later in 2019, increasing the likelihood the MPUC will delay its decision on the TCR rider update. In addition, on April 1, 2019, the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The estimated amount credited to Minnesota customers through the TCR rider through March 31, 2019 is approximately $2.5 million.

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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. Accordingly, in its 2018 annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to zero effective December 1, 2018. The remaining under-recovered balance was charged on customer billings in March and April 2019.

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 requested $13.1 million increase was net of reductions in North Dakota RRA, TCR and ECR rider revenues that would have resulted from a lower allowed rate of ROE 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 ROE of 10.3%. 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. 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 included $4.8 million related to tax reform and $1.2 million related to other updates.

In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. This compares with OTP’s March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval does not require any rate base adjustments from OTP’s original request and establishes a GCR rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements related to the TCJA and decreases in rider revenue recovery requirements. Final rates were effective February 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills. OTP has accrued an interim rate refund of $3.4 million as of March 31, 2019, which includes interest and $0.8 million in excess revenue collected for income taxes under interim rates in effect in January and February 2018.

Renewable Resource Adjustment—OTP has a North Dakota RRA 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.

Effective in February 2019 with the implementation of general rates based on the results of OTP’s 2017 general rate case, recovery of renewable resource costs previously being recovered through the North Dakota RRA rider transitioned to recovery in base rates.

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. Based on the order in the 2017 general rate case, only certain costs will remain subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the 2017 general rate case. This rider will continue to be updated annually for new or modified electric transmission facilities and associated operating costs.

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota. The ECR rider has provided for a return on investment at the level approved in OTP’s preceding general rate case and for recovery of OTP’s North Dakota share of environmental investments and costs approved for recovery under the rider. Prior to its 2017 general rate case reaching a final settlement and final rates going into effect on February 1, 2019, OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were being recovered through the ECR rider. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to ratepayers through the rider.

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Generation Cost Recovery Rider—On March 1, 2019 OTP filed a request with the NDPSC to establish an initial GCR rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements of its investment in Astoria Station.

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. Interim rates went into effect October 18, 2018. The second step in the request was an additional 1.7% revenue increase to recover costs for the proposed Merricourt wind generation facility when the facility goes into service.

The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The settlement includes approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and the Merricourt Project, which addresses the second step of the request for increased rates in South Dakota. The partial settlement also includes a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The settlement also allows OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. OTP expects a final determination on its allowed rate of ROE sometime during the second quarter of 2019.

OTP’s previously approved general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued in April 2011 and effective in June 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. OTP has a TCR rider in South Dakota. A supplemental filing to update the rider was made on January 29, 2018 to reflect updated costs and collections and incorporate the impact of the reduction in the federal corporate income tax rate under the TCJA. Effective October 18, 2018, with the implementation of interim rates under South Dakota general rate case proceedings, the TCR rate was decreased as a result of recovery of certain costs being shifted to recovery in interim rates and proposed for ongoing recoveries in final base rates at the end of the 2018 general rate case.

OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. On February 8, 2019 the SDPUC approved the supplemental filing and rates effective March 1, 2019. Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective January 1, 2019 and The Big Stone South – Ellendale project with a recovery date effective January 2020.

Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota. 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 South Dakota share of environmental investments and costs approved for recovery under the rider. Prior to interim rates going into effect on October 18, 2018 pending a final decision on OTP’s South Dakota general rate increase request, OTP’s South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxics Standards projects were being recovered through the ECR rider. With the initiation of interim rates, recovery of the costs previously being recovered under the ECR rider was transitioned to recovery under interim rates and the South Dakota ECR rider rate was reset to provide a refund to customers while interim rates are in effect.

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Rate Rider Updates

The following table provides summary information on the status of updates since January 1, 2017 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
2018 Incentive and Cost Recovery	R – April 1, 2019	October 1, 2019	$	11,926		$0.00710/kwh
2017 Incentive and Cost Recovery	A – October 4, 2018	November 1, 2018	$	10,283		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
Transmission Cost Recovery
2018 Annual Update–Scenario A	R – November 30, 2018	June 1, 2019	$	6,475		Various
–Scenario B			$	2,708		Various
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
Environmental Cost Recovery
2018 Annual Update	A – November 29, 2018	December 1, 2018	$	--		0% of base
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
Renewable Resource Adjustment
2018 Annual Update	A – August 29, 2018	November 1, 2018	$	5,886		$.00244/kwh
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2019 Annual Update	A – May 1, 2019	June 1, 2019	$	(235	)	-0.224% of base
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
Transmission Cost Recovery
2018 Supplemental Update	A – December 6, 2018	February 1, 2019	$	4,801		Various
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
Environmental Cost Recovery
2018 Update	A – December 19, 2018	February 1, 2019	$	(378	)	-0.310% of base
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
Generation Cost Recovery
2019 Initial Request	R – March 1, 2019	July 1, 2019	$	2,720		2.547% of base
South Dakota
Transmission Cost Recovery
2019 Annual Update	A – February 20, 2019	March 1, 2019	$	1,638		Various
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	1,171		Various
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
Environmental Cost Recovery
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	(189	)	-$0.00075/kwh
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh

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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)	2019			2018
Minnesota
Conservation Improvement Program Costs and Incentives1	$	2,152		$	2,516
Renewable Resource Recovery		1,316			525
Transmission Cost Recovery		641			(29	)
Environmental Cost Recovery		(1	)		(31	)
North Dakota
Transmission Cost Recovery		1,772			2,062
Renewable Resource Adjustment		729			1,967
Environmental Cost Recovery		575			1,821
Generation Cost Recovery		248			--
South Dakota
Transmission Cost Recovery		473			536
Conservation Improvement Program Costs and Incentives		244			229
Environmental Cost Recovery		(4	)		520
Total	$	8,145		$	10,116

¹Includes MNCIP costs recovered in base rates.

TCJA

The TCJA, passed in December 2017, reduced the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. At the time of passage, OTP’s electric rates had been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC each initiated dockets or proceedings to begin working with utilities to assess the impact of the lower rates on electric rates, and to develop regulatory strategies to incorporate the tax reduction into future electric rates, if warranted.

The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. On August 9, 2018 the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. On December 5, 2018 the MPUC issued its final order related to the TCJA docket directing OTP to return to ratepayers, in a one-time refund, the TCJA-related savings accrued prior to the refund effective date. OTP must amortize its protected excess accumulated deferred income taxes (ADIT) as early as U.S. Internal Revenue Service provisions allow and amortize its unprotected excess ADIT over ten years. OTP was instructed to use its 2017 year-end ADIT balance to calculate its excess ADIT balance. The order also directs OTP to use these savings to reduce customers’ base rates prospectively—allocating the savings to customers in proportion to the size of each customer’s bill, or to each customer class in proportion to the class’s size. OTP expects the rate change to occur in the second quarter of 2019 and a one-time refund to occur in the third quarter of 2019, pending MPUC approval of OTP’s January 3, 2019 compliance filing.

As described above, OTP’s current general rate cases in North Dakota and South Dakota reflect the ongoing impact of the TCJA in interim rates. OTP has accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurs under the lower federal tax rates in the TCJA. As of March 31, 2019, accrued refund liabilities related to the tax rate reduction were $10.4 million in Minnesota, $0.8 million in North Dakota for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018, and $0.3 million for FERC jurisdictional rates. The North Dakota liability was refunded with the interim rate refund in April 2019.

As of March 15, 2018, the FERC granted the request for waiver from a group of MISO transmission operators (including OTP) to revise inputs to their projected net revenue requirements for the 2018 rate year to reflect recent tax law changes.

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (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 suspension period, subject to ultimate approval by the FERC.

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MVPs—MVPs are designed to enable the MISO 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%. Several 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 went to 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, 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, 2019.

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 U.S. 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. The motion is currently pending before the FERC.

On October 16, 2018 the FERC issued an order proposing a methodology for addressing the issues that were remanded to the FERC by the D.C. Circuit in April 2017. The FERC order established a paper hearing on how the methodology should apply to the proceedings pending before the FERC involving NETOs’ ROE. In the order, the FERC selected a preliminary just and reasonable ROE for NETOs of 10.41%, exclusive of incentives, with a proposed cap on any pre-existing incentive-based total ROE at 13.08% and directed participants to submit supplemental briefs and additional written evidence regarding the proposed approaches to the Federal Power Act Section 206 inquiry and how to apply them to the NETO ROE complaints. On November 15, 2018, FERC issued an order establishing a paper hearing on whether and how a two-step ROE methodology developed for NETOs should apply to the ROE for MISO transmission owners. Initial briefs were due February 13, 2019 and reply briefs were due April 10, 2019. FERC is under no statutory timeline to act; however, the Company expects FERC to issue an order in the third or fourth quarter of 2019.

OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of March 31, 2019 related to the second MISO tariff ROE complaint is appropriate.

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

	March 31, 2019								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	$	6,355	$	116,835		$	123,190		see below
Accumulated ARO Accretion/Depreciation Adjustment1		--		7,302			7,302		asset lives
Conservation Improvement Program Costs and Incentives2		3,007		3,979			6,986			18
Deferred Marked-to-Market Losses1		1,432		557			1,989			21
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		1,958		--			1,958			12
Deferred Income Taxes1		--		1,557			1,557		asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		689		770			1,459			25
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1		--		1,143			1,143		asset lives
Debt Reacquisition Premiums1		203		701			904			162
North Dakota Deferred Rate Case Expenses Subject to Recovery1		416		--			416			12
Big Stone II Unrecovered Project Costs – South Dakota1		117		292			409			42
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		180		130			310			33
South Dakota Deferred Rate Case Expenses Subject to Recovery1		267		--			267			12
North Dakota Generation Cost Recovery Rider Accrued Revenues2		248		--			248			12
Recoverable Fuel and Purchased Power Costs – South Dakota1		197		--			197			12
Minnesota SPP Transmission Cost Recovery Tracker1		--		117			117		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1		52		--			52			4
Deferred Lease Expenses1		--		44			44			48
Minnesota Environmental Cost Recovery Rider Accrued Revenues2		38		--			38			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues2		34		--			34			12
Total Regulatory Assets	$	15,193	$	133,427		$	148,620
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	141,452		$	141,452		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,555			83,555		asset lives
Refundable Fuel Clause Adjustment Revenues – Minnesota		5,149		--			5,149			12
North Dakota Renewable Resource Recovery Rider Accrued Refund		901		--			901			12
North Dakota Environmental Cost Recovery Rider Accrued Refund		669		--			669			12
Refundable Fuel Clause Adjustment Revenues – North Dakota		537		--			537			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		272		--			272			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		225			225		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			21
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		103		--			103			12
Other		5		77			82			177
Total Regulatory Liabilities	$	7,787	$	225,496		$	233,283
Net Regulatory Asset/(Liability) Position	$	7,406	$	(92,069	)	$	(84,663	)

¹Costs subject to recovery without a rate of return.

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

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	December 31, 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	$	6,346	$	118,433		$	124,779		see below
Accumulated ARO Accretion/Depreciation Adjustment1		--		7,169			7,169		asset lives
Conservation Improvement Program Costs and Incentives2		5,995		3,285			9,280			21
Deferred Marked-to-Market Losses1		1,661		743			2,404			24
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		444		--			444			12
Deferred Income Taxes1		--		2,423			2,423		asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		681		947			1,628			28
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery1		--		986			986		asset lives
Debt Reacquisition Premiums1		207		753			960			165
North Dakota Deferred Rate Case Expenses Subject to Recovery1		455		--			455			12
Big Stone II Unrecovered Project Costs – South Dakota1		100		342			442			53
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1		240		--			240			12
South Dakota Deferred Rate Case Expenses Subject to Recovery1		178		--			178			12
Minnesota SPP Transmission Cost Recovery Tracker1		--		176			176		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues1		328		--			328			4
Minnesota Environmental Cost Recovery Rider Accrued Revenues2		121		--			121			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues2		452		--			452			12
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		17		--			17			12
Total Regulatory Assets	$	17,225	$	135,257		$	152,482
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	142,779		$	142,779		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,229			83,229		asset lives
North Dakota Renewable Resource Recovery Rider Accrued Refund		177		--			177			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		166			166		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			24
South Dakota Transmission Cost Recovery Rider Accrued Refund		168		--			168			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		207		--			207			12
Refundable Fuel Clause Adjustment Revenues		121		--			121			12
Other		5		108			113			180
Total Regulatory Liabilities	$	738	$	226,469		$	227,207
Net Regulatory Asset/(Liability) Position	$	16,487	$	(91,212	)	$	(74,725	)

¹Costs subject to recovery without a rate of return.

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

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

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

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

All Deferred Marked-to-Market Losses recorded as of March 31, 2019 relate to forward purchases of energy scheduled for delivery through December 2020.

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The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of March 31, 2019.

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

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.

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.

Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 162 months.

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

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.

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.

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

North Dakota Generation Cost Recovery (NDGCR) Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The March 31, 2019 balance represents amounts subject to recovery from North Dakota customers that have not been billed to North Dakota customers. The NDGCR is expected to go into effect in July 2019 pending NDPSC review and approval.

The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not been billed to Minnesota customers as of March 31, 2019.

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.

Deferred Lease Expenses: Under ASC 842 accounting rules, for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account on March 31, 2019 represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject to recovery in future periods under regulatory account treatment as cash payments are rendered.

The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are recoverable from Minnesota customers as of March 31, 2019.

The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of March 31, 2019. Currently, the rider is only being used to recover the amount of federal PTCs generated by OTP’s wind farms that were transferred from inclusion in the rider and applied as a reduction in revenue requirements to Minnesota base rates. Subsequent to applying the PTCs to base rates the PTCs expired. The Minnesota RRA rider is now being used to recover the shortfall in 

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base rates related to the expiration of the PTCs. Recovery will continue through the rider until interim or revised base rates are established in connection with OTP’s next Minnesota rate case.

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 are recoverable from North Dakota customers as of March 31, 2019.

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

North Dakota Renewable Resource Recovery 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, 2019.

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of March 31, 2019. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to Minnesota ratepayers through the rider.

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, 2019.

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.

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, 2019.

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, 2019.

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. Common Shares and Earnings Per Share

Shelf Registration

On May 3, 2018 the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 3, 2021.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2018 through March 31, 2019:

Common Shares Outstanding, December 31, 2018	39,664,884
Issuances:
Executive Stock Performance Awards (2016 shares earned)	102,198
Vesting of Restricted Stock Units	17,850
Retirements:
Shares Withheld for Individual Income Tax Requirements	(55,224	)
Common Shares Outstanding, March 31, 2019	39,729,708

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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, 2019 and 2018. 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:

	2019		2018
Weighted Average Common Shares Outstanding – Basic		39,657,321		39,550,874
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		158,159		223,162
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		63,398		59,130
Nonvested Restricted Shares		21,922		27,643
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,365		2,873
Total Dilutive Shares		245,844		312,808
Weighted Average Common Shares Outstanding – Diluted		39,903,165		39,863,682

The effect of dilutive shares on earnings per share for the three-month periods ended March 31, 2019 and 2018, resulted in no differences greater than $0.01 between basic and diluted earnings per share in either period.

6. Share-Based Payments

Stock Incentive Awards

On February 13, 2019 the following stock incentive awards were granted under the 2014 Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant- Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,600	$	49.6225	25% per year through February 6, 2023
Stock Performance Awards Granted:
Under Executive and Select Employee Agreements		47,800	$	42.875	December 31, 2021
Under Legacy Agreement		7,800	$	45.885	December 31, 2021

The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit 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 55,600 shares. For target performance the participants would earn an aggregate of 27,800 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,800 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, 2019 through December 31, 2021, 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, 2019 and the average closing price for the 20 trading days immediately preceding January 1, 2022. Actual payment may range from zero to 150% of the target amount, or up to 83,400 common shares. There are no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC Topic 718, Compensation – Stock Compensation, 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.

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Under the 2019 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to 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 vesting of these awards is accelerated and paid at target in the event of a change in control.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier 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, 2019, the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $6.2 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 stock-based payment programs for the three-month periods ended March 31, 2019 and 2018 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2019		2018
Stock Performance Awards Granted to Executive Officers	$	1,113	$	651
Restricted Stock Units Granted to Executive Officers		427		249
Restricted Stock Granted to Executive Officers		--		16
Restricted Stock Granted to Directors		165		166
Restricted Stock Units Granted to Non-Executive Employees		91		64
Totals	$	1,796	$	1, 146

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, 2019, the Company was in compliance with these financial 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 47.9% and 58.5% based on OTP’s 2018 capital structure petition effective by order of the MPUC on October 18, 2018. As of March 31, 2019, OTP’s equity-to-total-capitalization ratio including short-term debt was 53.2% and its net assets restricted from distribution totaled approximately $484 million. Total capitalization for OTP cannot currently exceed $1.2 billion.

27

8. Leases 

The Company adopted ASU 2016-02 and related updates (ASC Topic 842), which replaced previous lease accounting guidance, on January 1, 2019, using the modified retrospective method of adoption. As a result, prior periods have not been restated. ASC Topic 842 requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than 12 months. Adoption of the standard resulted in the recognition of net lease assets and lease liabilities of $20 million on January 1, 2019. The adoption of the new standard did not have a material effect on the Company’s consolidated statements of income or cash flows. In addition, the adoption did not have a material impact on the Company’s liquidity or the Company’s covenant compliance under its current debt agreements.

The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic 840. The Company also elected the practical expedient related to land easements, allowing for the continuation of historical accounting treatment for land easements on existing agreements at OTP. In addition, the Company has elected the hindsight practical expedient to determine the reasonably certain lease term for leases in place at the time of adoption. The Company has elected the practical expedient to not separate nonlease components from lease components on real estate leases for the purpose of determining the classification and the value of lease assets and lease liabilities at the inception of a lease.

The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than one year to approximately 10 years. If a lease contains an option to extend and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception. None of these leases met the criteria to be classified as financing leases. Of the operating leases in place on January 1, 2019, 50 were capitalized as right-of-use assets the remainder were month-to-month leases with no long-term obligations.

The right-of-use asset operating leases in place at the time of adoption were capitalized on the basis of their remaining payment obligation balances, discounted to present value based on the Company’s incremental borrowing rates (IBRs) appropriate to the leased asset and lease terms. The remaining payments for operating lease right-of-use assets are being charged to expense on a straight-line basis over the life of the lease.

For the Company’s current lease obligations, no explicit interest rates were stated in the lease agreements and no implicit rates could be determined based on the terms of the agreements. Therefore, in all cases, the Company has applied a formula-based IBR appropriate to the individual company, type of lease and lease term. 

The breakdown of right-of-use assets and lease liabilities as of March 31, 2019 by business segment is provided in the following table.

(in thousands)	Electric			Manufacturing			Plastics			Corporate			Total
Right of Use Assets – Operating Leases:
Gross	$	3,421		$	16,976		$	666		$	767		$	21,830
Accumulated Amortization		(257	)		(734	)		(97	)		(30	)		(1,118	)
Net of Accumulated Amortization	$	3,164		$	16,242		$	569		$	737		$	20,712
Obligations:
Current Operating Lease Liabilities	$	913		$	2,458		$	379		$	150		$	3,900
Long-Term Operating Lease Liabilities		2,470			13,852			190			648			17,160
Total Lease Liabilities	$	3,383		$	16,310		$	569		$	798		$	21,060

28

The amounts of the Company’s right-of-use operating lease obligations for each of the five years in the period 2019 through 2023 and in aggregate for the years beyond 2023 are presented in the following table, including obligations under lease agreements that had not commenced as of March 31, 2019.

	Right-of-Use Operating Leases
(in thousands)	OTP			Nonelectric			Total
2019	$	845		$	3,078		$	3,923
2020		1,115			3,948			5,063
2021		1,091			3,657			4,748
2022		207			3,529			3,736
2023		196			3,209			3,405
Beyond 2023		447			8,023			8,470
Total Minimum Obligations	$	3,901		$	25,443		$	29,344
Interest Component of Obligations		(355	)		(4,376	)		(4,731	)
Present Value of Leases Commencing after March 31, 2019		(163	)		(3,390	)		(3,553	)
Present Value of Minimum Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

The Company’s total minimum lease obligations reported in the table above include obligations for a ten-year lease of a warehouse by T.O. Plastics entered into in 2018 and commencing in July 2019 and a 27-month lease of 20 additional coal rail cars to transport coal to OTP’s Hoot Lake Plant entered into and commencing in April 2019.

The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 6 years and the weighted-average discount rate is 5.0%.

A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 on January 1, 2019 and its operating lease obligations on March 31, 2019 is provided in the table below.

(in thousands)	OTP			Nonelectric			Total
Operating Lease Obligations, January 1, 2019	$	3,609		$	16,760		$	20,369
Non-cash Acquisition of Right-of-Use Assets		--			1,725			1,725
Lease Obligation Payments		(270	)		(1,020	)		(1,290	)
Interest Component of Lease Obligation Payment		44			212			256
Operating Lease Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service.

The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income.

The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the three-month period ending March 31, 2019 is presented in the following table.

(in thousands)	Operating Lease Cost		Variable Lease Cost		Total Lease Cost
Plant in Service or CWIP	$	9	$	--	$	9
Inventory		225		--		225
Cost of Products Sold		1,036		27		1,063
Electric Operation and Maintenance Expenses		66		--		66
Other Nonelectric Expenses		54		--		54
Total	$	1,390	$	27	$	1,417

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9. Commitments and Contingencies

Construction and Other Purchase Commitments

At March 31, 2019 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $70.5 million. At December 31, 2018 OTP had commitments under contracts, including its share of construction program commitments and other nonlease commitments, extending into 2021 of approximately $64.5 million. At March 31, 2019 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $4.7 million. At December 31, 2018 T.O. Plastics had commitments for the purchase of resin through December 31, 2021 of approximately $5.0 million.

Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts

OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2042. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2020. OTP has an agreement with Peabody COALSALES, LLC for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020. There is no fixed minimum purchase requirement under this agreement but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement, except for a portion contracted to be purchased in 2019 under a prior existing agreement with Contura Coal Sales, LLC. OTP has an all-requirements agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. There are no fixed minimum purchase requirements under this agreement.

OTP Land Easements

OTP has commitments to make future payments for land easements not classified as leases, extending into 2034 of approximately $10.8 million.

Contingencies

OTP had a $1.6 million refund liability on its balance sheet as of March 31, 2019 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. As discussed in note 3 in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current facts and circumstances and is awaiting further action by the FERC before determining if a change in this estimate will be needed.

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 potential ROE refund described above, the most significant contingencies that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, and litigation matters. The Company currently is not aware of any items that would result in charges in excess of established reserve amounts.

In 2015 the Environmental Protection Agency (EPA), acting under Section 111(d) of the Clean Air Act, issued the Clean Power Plan which required states to submit plans to limit carbon dioxide emissions from certain fossil fuel-fired power plants. The rule is not currently in effect as a result of a stay by the Supreme Court in 2016. In 2017, the EPA issued a Notice of Proposed Rulemaking to repeal the Clean Power Plan; comments were due in April 2018.

On August 21, 2018 the EPA proposed a replacement for the Clean Power Plan -- the Affordable Clean Energy (ACE) Rule. Among other things, the ACE Rule determines that the best system of emission reduction for greenhouse gas emissions from coal-fired power plants is to improve the plants’ heat rates, identifies a list of “candidate technologies” for improving a plant’s heat rate and proposes that physical or operational changes to a power plant would not be a “major modification” triggering extensive New Source Review, if the change does increase hourly emissions. If the ACE Rule goes into effect, states will have three years after the final rule to submit a state implementation plan.

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, 2019 will not be material.

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10. Short-Term and Long-Term Borrowings

The following table presents the status of the Company’s lines of credit as of March 31, 2019 and December 31, 2018:

(in thousands)	Line Limit		In Use on March 31, 2019		Restricted due to Outstanding Letters of Credit		Available on March 31, 2019		Available on December 31, 2018
Otter Tail Corporation Credit Agreement	$	130,000	$	27,742	$	--	$	102,258	$	120,785
OTP Credit Agreement		170,000		15,859		300		153,841		160,316
Total	$	300,000	$	43,601	$	300	$	256,099	$	281,101

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, 2019 and December 31, 2018:

March 31, 2019 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	15,859	$	27,742	$	43,601
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
PACE Note, 2.54%, due March 18, 2021				480		480
Total	$	512,000	$	80,480	$	592,480
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		174		174
Unamortized Long-Term Debt Issuance Costs		1,890		394		2,284
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,110	$	79,912	$	590,022
Total Short-Term and Long-Term Debt (with current maturities)	$	525,969	$	107,828	$	633,797

December 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	9,384	$	9,215	$	18,599
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
PACE Note, 2.54%, due March 18, 2021				523		523
Total	$	512,000	$	80,523	$	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		172		172
Unamortized Long-Term Debt Issuance Costs		1,942		407		2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,058	$	79,944	$	590,002
Total Short-Term and Long-Term Debt (with current maturities)	$	519,442	$	89,331	$	608,773

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11. Pension Plan and Other Postretirement Benefits

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Service Cost—Benefit Earned During the Period	$	1,373		$	1,615
Interest Cost on Projected Benefit Obligation		3,603			3,363
Expected Return on Assets		(5,325	)		(5,300	)
Amortization of Prior-Service Cost:
From Regulatory Asset		1			4
From Other Comprehensive Income1		2			--
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,163			1,784
From Other Comprehensive Income1		27			44
Net Periodic Pension Cost2	$	844		$	1,510
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of Costs:
Service costs included in OTP capital expenditures	$	390		$	328
Service costs included in electric operation and maintenance expenses		950			1,247
Service costs included in other nonelectric expenses		33			40
Nonservice costs capitalized as regulatory assets		(150	)		(21	)
Nonservice costs included in nonservice cost components of postretirement benefits		(379	)		(84	)

Cash flows—The Company had no minimum funding requirement as of December 31, 2018 but made a discretionary plan contribution of $10 million in January 2019.

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)	2019		2018
Service Cost—Benefit Earned During the Period	$	105	$	100
Interest Cost on Projected Benefit Obligation		434		399
Amortization of Prior Service Cost:
From Regulatory Asset		1		4
From Other Comprehensive Income1		4		10
Amortization of Net Actuarial Loss:
From Regulatory Asset		31		67
From Other Comprehensive Income1		87		165
Net Periodic Pension Cost2	$	662	$	745
1Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits.
2Allocation of Costs:
Service costs included in electric operation and maintenance expenses	$	26	$	25
Service costs included in other nonelectric expenses		79		75
Nonservice costs included in nonservice cost components of postretirement benefits		557		645

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Service Cost—Benefit Earned During the Period	$	321		$	382
Interest Cost on Projected Benefit Obligation		770			645
Amortization of Net Actuarial Loss:
From Regulatory Asset		393			412
From Other Comprehensive Income1		10			10
Net Periodic Postretirement Benefit Cost2	$	1,494		$	1,449
Effect of Medicare Part D Subsidy	$	(45	)	$	(37	)
1Corporate cost included in nonservice cost components of postretirement benefits.
2Allocation of Costs:
Service costs included in OTP capital expenditures	$	91		$	78
Service costs included in electric operation and maintenance expenses		223			294
Service costs included in other nonelectric expenses		7			10
Nonservice costs capitalized as regulatory assets		333			217
Nonservice costs included in nonservice cost components of postretirement benefits		840			850

12. Fair Value of Financial Instruments

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

Cash 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, 2019 and December 31, 2018 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, 2019						December 31, 2018
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	891		$	891		$	861		$	861
Short-Term Debt		(43,601	)		(43,601	)		(18,599	)		(18,599	)
Long-Term Debt including Current Maturities		(590,196	)		(611,219	)		(590,174	)		(601,513	)

13. Property, Plant and Equipment

No update required for interim reporting period.

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14. Income Tax Expense

The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three-month periods ended March 31, 2019 and 2018:

	Three Months Ended March 31,
(in thousands)	2019			2018
Income Before Income Taxes	$	31,952		$	30,009
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)		8,308			7,802
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates		(983	)		(1,073	)
Excess Tax Deduction – Equity Method Stock Awards		(827	)		(624	)
Corporate Owned Life Insurance		(409	)		(8	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(258	)
Research and Development and Other Tax Credits		(188	)		(180	)
Allowance for Funds Used During Construction – Equity		(86	)		(167	)
Federal Production Tax Credits (PTCs)		--			(1,120	)
Other Comprehensive Income Deferred Tax Rate Adjustment		--			(531	)
Other Items – Net		71			(47	)
Income Tax Expense	$	5,628		$	3,794
Effective Income Tax Rate		17.6	%		12.6	%

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

(in thousands)	2019		2018
Balance on January 1	$	1,282	$	684
Increases Related to Tax Positions for Current Year		38		36
Uncertain Positions Resolved During Year		--		(44	)
Balance on March 31	$	1,320	$	676

The balance of unrecognized tax benefits as of March 31, 2019 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2019 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, 2019.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of May 1, 2019, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2015 for federal, Minnesota and North Dakota income taxes.

34

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, 2019 and 2018 followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2019 and our business outlook for the remainder of 2019.

Comparison of the Three Months Ended March 31, 2019 and 2018

Consolidated operating revenues were $246.0 million for the three months ended March 31, 2019 compared with
$241.3 million for the three months ended March 31, 2018. Operating income was $39.6 million for the three months ended March 31, 2019 compared with $37.6 million for the three months ended March 31, 2018. The Company recorded diluted earnings per share of $0.66 for the three months ended March 31, 2019 compared with $0.66 for the three months ended March 31, 2018.

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, 2019 and 2018 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, 2019		March 31, 2018
Operating Revenues:
Electric	$	14	$	15
Nonelectric		3		(1	)
Costs of Products Sold		17		5
Other Nonelectric Expenses		--		9

Electric

	Three Months Ended
	March 31,									%
(in thousands)	2019			2018			Change			Change
Retail Sales Revenues from Contracts with Customers	$	114,955		$	109,180		$	5,775			5.3
Changes in Accrued Revenues under Alternative Revenue Programs		(1,049	)		(875	)		(174	)		19.9
Total Retail Sales Revenue	$	113,906		$	108,305		$	5,601			5.2
Transmission Services Revenue		10,862			11,903			(1,041	)		(8.7	)
Wholesale Revenues – Company Generation		1,527			1,015			512			50.4
Other Revenues		1,814			1,742			72			4.1
Total Operating Revenues	$	128,109		$	122,965		$	5,144			4.2
Production Fuel		18,920			18,706			214			1.1
Purchased Power – System Use		21,952			21,593			359			1.7
Electric Operation and Maintenance Expenses		38,382			39,475			(1,093	)		(2.8	)
Depreciation and Amortization		14,485			13,922			563			4.0
Property Taxes		3,959			3,835			124			3.2
Operating Income	$	30,411		$	25,434		$	4,977			19.6
Electric Megawatt-hour (mwh) Sales
Retail mwh Sales		1,478,139			1,453,893			24,246			1.7
Wholesale mwh Sales – Company Generation		39,334			39,404			(70	)		(0.2	)
Heating Degree Days		4,070			3,591			479			13.3

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

	Three Months ended March 31,
	2019			2018
Heating Degree Days		119.5	%		106.6	%

35

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kilowatt-hour (kwh) sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first quarters of 2019 and 2018 and between quarters:

	2019 vs Normal		2018 vs Normal		2019 vs 2018
Effect on Diluted Earnings Per Share	$	0.07	$	0.02	$	0.05

The $5.6 million increase in retail sales revenue includes:

● A $2.8 million increase in revenues related to increased consumption due to colder weather in the first quarter of 2019, evidenced by the 13.3% increase in heating degree days between the quarters.

● A $1.5 million increase in retail revenue in South Dakota due to the reversal of an expected refund related to reduced revenue requirements from January 1, 2018 through October 17, 2018 associated with the Tax Cut and Jobs Act (TCJA). Refund of this amount is not required under terms of the 2018 South Dakota rate case settlement agreement reached on March 1, 2019.

● A $1.1 million increase in South Dakota revenues related to an interim rate increase that went into effect on October 18, 2018.

● A $0.8 million increase in Minnesota Renewable Rider revenues due to increased cost recovery requirements resulting from the expiration of federal Production Tax Credits (PTCs) in November 2018 on Otter Tail Power Company’s (OTP’s) Ashtabula wind farm.

● A $0.7 million increase in Minnesota Transmission Cost Recovery rider revenues related to the recovery of investment and operating costs of the Big Stone South–Ellendale 345-kilovolt transmission line energized on February 6, 2019.

● A $0.4 million increase in retail revenue related to the recovery of increased fuel and purchased power costs. Fuel costs increased due to a 25.4% increase in generation from the higher-fuel-cost Hoot Lake Plant, partially offset by a 12.7% decrease in generation output from Coyote Station, a lower-fuel-cost generation unit. Increased demand due to the colder weather in 2019 drove market prices for electricity higher which resulted in increased dispatch of Hoot Lake Plant. Coyote Station was taken offline on March 26, 2019 for a planned spring maintenance outage.

partially offset by:

● A $1.4 million reduction in revenue due to a decrease in kwh sales to industrial and other customers, exclusive of the weather-related increase in retail kwh sales.

● A $0.3 million decrease in Minnesota Conservation Improvement Program (CIP) cost recovery revenues due to a decrease in CIP expenditures in 2019.

Transmission services revenue decreased $1.0 million mainly due to a $0.9 million decrease in Midwest Independent System Operator, Inc. (MISO) tariff revenue related to decreases in levels of recoverable transmission costs incurred.

Wholesale electric revenues increased $0.5 million due to a higher wholesale electric prices. While wholesale kwh sales decreased 0.2%, higher wholesale prices resulted in increased revenues and a $0.3 million increase in margins on wholesale energy sales from OTP’s generating units in the first quarter of 2019 compared with the first quarter of 2018.

Production fuel costs increased $0.2 million due to a 0.5% increase in the cost of fuel per kwh generated and a 0.6% increase in kwhs generated from our fuel-burning plants. As noted above, the increase in fuel costs per kwh generated resulted from a 25.4% increase in generation from the higher-fuel-cost Hoot Lake Plant partially offset by a 12.7% decrease in generation from Coyote Station, a lower-fuel-cost generation unit.

The cost of purchased power to serve retail customers increased $0.4 million. The cost per kwh purchased increased by 8.5% while kwhs purchased decreased 6.3%. Increased system demand driven by colder winter weather in 2019 lead to the increase in wholesale market prices for electricity.

Electric operation and maintenance expenses decreased $1.1 million mostly due to lower vegetation maintenance and employee benefit costs.

Depreciation expense increased $0.6 million mainly due to 2018 capital additions.

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Manufacturing

	Three Months Ended
	March 31,							%
(in thousands)	2019		2018		Change			Change
Operating Revenues	$	77,822	$	68,662	$	9,160			13.3
Cost of Products Sold		59,239		52,041		7,198			13.8
Operating Expenses		8,080		6,873		1,207			17.6
Depreciation and Amortization		3,682		3,854		(172	)		(4.5	)
Operating Income	$	6,821	$	5,894	$	927			15.7

The $9.2 million increase in revenues in our Manufacturing segment includes the following:

● Revenues at BTD Manufacturing, Inc. (BTD) increased $10.3 million, due to growth in parts revenue of $11.4 million, including increased sales in agricultural, construction, recreational vehicle, lawn and garden and industrial equipment end markets. Included in the parts revenue increase is the pass through of higher material costs of $6.3 million, with the remaining increase due to higher sales volume and an increase in pricing unrelated to material cost increases. The increase in parts revenue was partially offset by a $1.2 million decrease in tooling revenues. Revenues from scrap metal sales were essentially flat quarter over quarter, with a 6.8% increase in scrap volume offset by a 6.8% decrease in scrap metal prices.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, decreased $1.2 million primarily due to decreased sales of horticultural containers and industrial and life sciences products. The decline in horticultural sales is due to a customer moving some product to a competitor with injection molding capabilities and lower sales to two customers related to the timing of orders. Industrial sales were down due to a customer bringing more production in house. Challenging weather conditions in February were also a factor in weaker sales in the northern region of the United States. Product availability in February and the partial collapse of a section of a warehouse roof in March due to heavy snow also contributed to a slow start in horticultural sales in 2019.

The $7.2 million increase in cost of products sold in our Manufacturing segment includes the following:

● Cost of products sold at BTD increased $7.8 million as a result of both the increased sales volume and the $6.3 million in higher material costs passed through to customers.

● Cost of products sold at T.O. Plastics decreased $0.6 million related to the decrease in sales volume partly offset by an increase in unabsorbed labor and overhead costs due to the decrease in production.

The $1.2 million increase in operating expenses in our Manufacturing segment includes a $1.0 million increase at BTD mainly due to increases in labor, benefit and recruiting costs for additional employees. Operating expenses at T.O. Plastics increased $0.2 million due to a loss associated with the partial collapse of a warehouse roof in the first quarter of 2019.

Plastics

	Three Months Ended
	March 31,							%
(in thousands)	2019		2018		Change			Change
Operating Revenues	$	40,058	$	49,653	$	(9,595	)		(19.3	)
Cost of Products Sold		31,360		36,749		(5,389	)		(14.7	)
Operating Expenses		2,665		2,614		51			2.0
Depreciation and Amortization		891		951		(60	)		(6.3	)
Operating Income	$	5,142	$	9,339	$	(4,197	)		(44.9	)

Plastics segment revenues decreased $9.6 million due to a 16.8% decrease in pounds of pipe sold and a 3.1% decrease in polyvinyl chloride (PVC) pipe prices. An overall decrease in quarter-over-quarter sales volume was anticipated. Weather conditions across our sales territory also negatively impacted first quarter 2019 sales. Cost of products sold decreased $5.4 million due to the decrease in sales volume partially offset by a 2.5% increase in the cost per pound of pipe sold. The decrease in pipe prices in combination with the increase in costs per pound of pipe sold resulted in a 19.0% decrease in gross margin per pound of PVC pipe sold. Plastics segment operating and depreciation expenses were essentially unchanged between the quarters resulting in the $4.2 million decrease in segment operating income.

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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)	2019		2018		Change			Change
Operating Expenses	$	2,732	$	3,016	$	(284	)		(9.4	)
Depreciation and Amortization		73		36		37			102.8

Corporate operating expenses decreased $0.3 million, mainly as a result of decreases in professional and contracted services and dues and subscription expenses.

Interest Charges

The $0.5 million increase in interest charges for the three months ended March 31, 2019 compared with the three months ended March 31, 2018 is due to a $9.6 million increase in average debt outstanding between the quarters, the replacement of $100 million of short-term debt bearing interest at 2.88% with long-term debt bearing interest at 4.07% in February 2018 and an increase in average short-term debt interest rates of approximately 1.1% between the quarters. A $0.1 million decrease in capitalized interest at OTP also contributed to the increase in interest charges between the quarters.

Nonservice Cost Components of Postretirement Benefits

The $0.4 million decrease in nonservice cost components of postretirement benefits in the three months ended March 31, 2019 compared with the three months ended March 31, 2018, is mostly due to a decrease in nonservice costs of the Company’s pension plans, mainly actuarial loss amortization expenses.

Income Tax Expense

Income tax expense increased $1.8 million in the three months ended March 31, 2019 compared with the three months ended March 31, 2018 mainly due to a $1.1 million decrease in federal PTCs resulting from the expiration of PTCs on OTP’s Ashtabula wind farm in November 2018 and a $1.9 million increase in income 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 before income taxes on our consolidated statements of income for the three-month periods ended March 31, 2019 and 2018:

	Three Months Ended March 31,
(in thousands)	2019			2018
Income Before Income Taxes	$	31,952		$	30,009
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)		8,308			7,802
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates		(983	)		(1,073	)
Excess Tax Deduction – Equity Method Stock Awards		(827	)		(624	)
Corporate Owned Life Insurance		(409	)		(8	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(258	)
Research and Development and Other Tax Credits		(188	)		(180	)
Allowance for Funds Used During Construction – Equity		(86	)		(167	)
Federal PTCs		--			(1,120	)
Other Comprehensive Income Deferred Tax Rate Adjustment		--			(531	)
Other Items – Net		71			(47	)
Income Tax Expense	$	5,628		$	3,794
Effective Income Tax Rate		17.6	%		12.6	%

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 is no longer eligible for PTCs with the expiration of PTCs for its Ashtabula wind farm in November 2018. 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, 2019 and December 31, 2018:

(in thousands)	Line Limit		In Use on March 31, 2019		Restricted due to Outstanding Letters of Credit		Available on March 31, 2019		Available on December 31, 2018
Otter Tail Corporation Credit Agreement	$	130,000	$	27,742	$	--	$	102,258	$	120,785
OTP Credit Agreement		170,000		15,859		300		153,841		160,316
Total	$	300,000	$	43,601	$	300	$	256,099	$	281,101

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 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.

Equity or debt financing will be required in the period 2019 through 2023 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, 2019 our board of directors increased the quarterly dividend from $0.335 to $0.35 per common share.

Cash provided by operating activities was $17.1 million for the three months ended March 31, 2019 compared with cash provided by operating activities of $4.6 million for the three months ended March 31, 2018. The primary reason for the $12.5 million increase in cash provided by operations between the quarters was a $10.0 million decrease in discretionary contributions to our funded pension plan. A $13.9 million net increase in cash provided by changes in noncurrent liabilities and deferred credits was mostly offset by a $12.0 million decrease in cash from accounts receivable between the quarters primarily related to an increase in receivables in the first quarter of 2019. We do not expect any issues in collecting the outstanding receivables.

Net cash used in investing activities was $25.4 million for the three months ended March 31, 2019 compared with $23.8 million for the three months ended March 31, 2018. The $1.6 million increase in cash used for investing activities includes a $0.8 million increase in capital expenditures at BTD and a $0.6 million increase in capital expenditures at OTP.

Net cash provided by financing activities was $8.3 million for the three months ended March 31, 2019 compared with $4.1 million for the three months ended March 31, 2018. Financing activities in the first quarter of 2019 included proceeds of $25.0 million from borrowings of $18.5 million under the Otter Tail Corporation Credit Agreement to provide working capital for our manufacturing companies and $6.5 million under the OTP credit agreement to fund OTP capital expenditures. The line of credit borrowings were partially offset by $13.9 million in common dividend payments and $2.7 million in payments for the retirement of capital stock.

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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 were $13.3 million in the first quarter of 2018.

CAPITAL REQUIREMENTS

2019-2023 Capital Expenditures

The following table shows our 2018 capital expenditures and 2019 through 2023 anticipated capital expenditures and electric utility average rate base:

(in millions)	2018		2019		2020		2021		2022		2023		Total
Capital Expenditures:
Electric Segment:
Renewables and Natural Gas Generation			$	103	$	292	$	18	$	83	$	2	$	498
Transformative Technology and Infrastructure				3		25		39		46		32		145
Transmission (includes replacements)				37		38		13		11		23		122
Other				40		38		50		37		43		208
Total Electric Segment	$	87	$	183	$	393	$	120	$	177	$	100	$	973
Manufacturing and Plastics Segments		18		20		18		17		23		19		97
Total Capital Expenditures	$	105	$	203	$	411	$	137	$	200	$	119	$	1,070
Total Electric Utility Ending Rate Base	$	1,112	$	1,210	$	1,510	$	1,539	$	1,614	$	1,631

The consolidated capital expenditure plan for the 2019-2023 time period calls for $1.1 billion based on the need for additional wind and solar in rate base, the Astoria Station natural gas-fired plant that is part of our replacement solution for Hoot Lake Plant when it is retired in 2021, the Merricourt wind generation project, technology-related investments and transmission investments. Given the increased capital expenditure plan, our compounded annual growth rate in rate base is projected to be 7.9% over the 2018 to 2023 timeframe.

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 2019 through 2023 timeframe.

Astoria Station—OTP is constructing this 245-megawatt (MW) simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota 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 $158 million. A final order granting an Advance Determination of Prudence (ADP) for Astoria Station was issued by the North Dakota Public Service Commission (NDPSC) on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the South Dakota Public Utilities Commission (SDPUC) issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a Generation Cost Recovery rider for future recovery of costs incurred for Astoria Station. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the Federal Energy Regulatory Commission (FERC) in January 2019. As of March 31, 2019, OTP had capitalized approximately $7.7 million in development costs associated with Astoria Station.

Merricourt Project—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 and certain specified liabilities associated with a 150-MW wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement will close on satisfaction of various closing conditions (including regulatory approvals). Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF pursuant to which EDF will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $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 customary representations, warranties, covenants and indemnities for this type of transaction. 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, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on January 10, 2018. A final order for an ADP, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. The Merricourt generation interconnection agreement with MISO was approved by the FERC in April 

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2019. Construction of the Merricourt Project will begin after closing on the Purchase Agreement, anticipated to occur in the last half of 2019. As of March 31, 2019, OTP had capitalized approximately $5.3 million in development costs associated with the Merricourt Project.

Contractual Obligations

The Company had no materially significant increases in contractual obligations in the first quarter of 2019.

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 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 Plan expires on May 3, 2021.

Short-Term Debt

The following table presents the status of our lines of credit as of March 31, 2019 and December 31, 2018:

(in thousands)	Line Limit		In Use on March 31, 2019		Restricted due to Outstanding Letters of Credit		Available on March 31, 2019		Available on December 31, 2018
Otter Tail Corporation Credit Agreement	$	130,000	$	27,742	$	--	$	102,258	$	120,785
OTP Credit Agreement		170,000		15,859		300		153,841		160,316
Total	$	300,000	$	43,601	$	300	$	256,099	$	281,101

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the OTC 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 OTC Credit Agreement. On October 31, 2018 the OTC Credit Agreement was amended to extend its expiration date by one year from October 31, 2022 to October 31, 2023. 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 OTC 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 OTC Credit Agreement contains a number of restrictions on us and the businesses of our wholly owned subsidiary, Varistar Corporation and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The OTC Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTC 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 OTC Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the OTC 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, 2018 the OTP Credit Agreement was amended to extend its expiration date by one year from October 31, 2022 to October 31, 2023. 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.

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Both the OTC Credit Agreement and the OTP Credit Agreement currently expire on October 31, 2023. Borrowings under these agreements currently use LIBOR as the base to determine the applicable interest rate. LIBOR is currently expected to be eliminated by January 1, 2022. Both agreements contain a provision to determine how interest rates will be established in the event a replacement for LIBOR has not been identified before the agreement expires. The process calls for the parties to jointly agree on an alternate rate of interest to LIBOR, such as the Secured Overnight Financing Rate, that gives due consideration to prevailing market convention for determining a rate of interest for syndicated loans in the United States at such time. The parties will enter into amendments to these agreements to reflect any alternate rate of interest and other related changes to the agreements as may be applicable. If for any reason an agreement cannot be reached on an alternate rate of interest, then any borrowings under the agreements will be determined using the Prime Rate plus a margin based on the Company’s and OTP’s long-term debt ratings at the time of the borrowings. If the alternate rate of interest agreed to by the parties is less than zero, such rate shall be deemed to be zero for the purposes of the credit agreement.

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.

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 a Term Loan Agreement.

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 

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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.

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.

43

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, 2019.

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 OTC 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, 2019, our Interest and Dividend Coverage Ratio calculated under the requirements of the OTC Credit Agreement and the 2016 Note Purchase Agreement was 4.39 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, 2019, 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 3.44 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, 2019, our ratio of Interest-bearing Debt to Total Capitalization was 0.46 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation nor OTP had any Priority Indebtedness outstanding as of March 31, 2019.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $3.0 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.

44

2019 BUSINESS OUTLOOK

We anticipate 2019 diluted earnings per share to be in the range of $2.10 to $2.25. We have taken into consideration strategies for improving future operating results, the cyclical nature of some of our businesses and current regulatory factors facing our Electric segment. We expect capital expenditures for 2019 to be $203 million compared with actual cash used for capital expenditures of $105 million in 2018. Our planned expenditures for 2019 include $61 million for the Merricourt Project and $40 million for Astoria Station.

Segment components of our 2019 earnings per share guidance range compared with 2018 actual earnings are as follows:

	2018 EPS by Segment			2019 Guidance February 18, 2019						2019 Guidance May 6, 2019
Diluted Earnings Per Share				Low			High			Low			High
Electric	$	1.36		$	1.46		$	1.49		$	1.48		$	1.51
Manufacturing	$	0.32		$	0.37		$	0.41		$	0.35		$	0.39
Plastics	$	0.60		$	0.44		$	0.48		$	0.44		$	0.48
Corporate	$	(0.22)	)	$	(0.17	)	$	(0.13	)	$	(0.17	)	$	(0.13	)
Total	$	2.06		$	2.10		$	2.25		$	2.10		$	2.25
Return on Equity		11.5	%		11.5	%		12.3	%		11.5	%		12.3	%

The following items contribute to our earnings guidance for 2019.

● We expect 2019 Electric segment net income to be higher than 2018 segment net income and are increasing our 2019 guidance range for this segment based on:

o SDPUC approval of a partial rate-case settlement on March 1, 2019 on all issues in the rate case except return on equity. The business outlook assumes an annual net revenue increase of approximately $2.3 million. The partial settlement also allowed us to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018. This outcome favorably impacts 2019 earnings by approximately $0.02 per share.

o Increases in allowance for funds used during construction (AFUDC) for planned capital projects, including the Merricourt Project, and increases in AFUDC and North Dakota Generation Cost Recovery Rider revenue related to Astoria Station. Both of these projects are expected to begin construction in 2019.

o Increased revenues from completion of the Big Stone South–Ellendale project and additional transmission investments related to our South Dakota Transmission Reliability project.

o Decreased operating and maintenance expenses due to decreasing costs of pension, medical, workers compensation and retiree medical benefits. The decrease in pension costs is a result of an increase in the discount rate from 3.90% to 4.50%.

partially offset by: 

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

o An extension of the planned outage at Coyote Station due to turbine rotor blade damage that was discovered in the early stages of the planned outage.

● We still expect 2019 net income from our Manufacturing segment to increase over 2018, but we are lowering the 2019 guidance range for this segment due to first quarter volume softness and the expected impact of the partial collapse and replacement of a warehouse roof at TO Plastics. The overall increase in segment earnings in 2019 is based on:

o Increased sales at BTD driven by growth in the recreational vehicle, lawn and garden and agricultural end markets. Most of this growth is organic with our existing customer base. Scrap revenues are expected to increase as well based on increased volume with scrap prices staying flat between the years.

o A decrease in earnings from T.O. Plastics mainly driven by the reasons mentioned above.

o Backlog for the manufacturing companies of approximately $165 million for 2019 compared with $142 million one year ago.

● We expect 2019 net income from the Plastics segment to be lower than 2018 based on lower expected operating margins in 2019. This is due to expected increasing resin prices on similar sales volumes in 2019 compared to 2018.

● Corporate costs, net of tax, are expected to be lower in 2019 than in 2018.

45

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, 2018. There were no material changes in critical accounting policies or estimates during the quarter ended March 31, 2019.

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, 2018, as well as the various factors described below:

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

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

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

● 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, 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 our businesses through capital projects, including infrastructure and new technology additions, or to grow or realign our businesses through acquisitions or 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.

46

● 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 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.

● Our electric 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.

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

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

● Changes to regulation of generating plant emissions, including but not limited to carbon dioxide emissions and regional haze regulation under state implementation plans, could affect our operating costs and the costs of supplying electricity to our customers and the economic viability of continued operation of certain of our steam-powered electric plants.

● Competition from foreign and domestic manufacturers, the price and availability of raw materials, trade policy and tariffs affecting prices and markets for raw material and manufactured products, 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 our plastics business.

● We compete against many 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, 2019 we had exposure to market risk associated with interest rates because we had $27.7 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.50% under the OTC Credit Agreement and OTP had $15.9 million in short-term debt outstanding on March 31, 2019 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, 2019 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.

47

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, 2019, 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, 2019.

During the quarter ended March 31, 2019, OTP implemented a new customer information system (CIS). This system was implemented as part of a technology initiative and not as a result of any identified deficiencies in internal controls over financial reporting. While changes in internal controls have been implemented in association with the transition to the new system during the first quarter of 2019, we believe that none of these changes materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. Additionally, there were no other changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are 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 28 through 35 of our Annual Report on Form 10-K for the year ended December 31, 2018.

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 2019 under our 2014 Stock Incentive Plan: 

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
January 2019		--		--
February 2019		55,224	$	49.44
March 2019		--		--
Total		55,224

48

Item 6.      Exhibits

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

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

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

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

101 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended March 31, 2019, 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) Consolidated Statements of Common Shareholders’ Equity (v) the Consolidated Statements of Cash Flows and (vi) 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.

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, 2019

49

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, 2019

/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, 2019

/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, 2019 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, 2019

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, 2019 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, 2019

XML

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
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 Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		39,754,652
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false

XML

Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 891	$ 861
Accounts Receivable:
Trade—Net	113,144	75,144
Other	8,827	9,741
Inventories	106,732	106,270
Unbilled Receivables	18,928	23,626
Income Taxes Receivable		2,439
Regulatory Assets	15,193	17,225
Other	9,986	6,114
Total Current Assets	273,701	241,420
Investments	9,220	8,961
Other Assets	38,653	35,759
Goodwill	37,572	37,572
Other Intangibles—Net	12,154	12,450
Regulatory Assets	133,427	135,257
Right of Use Assets - Operating Leases	20,712
Plant
Electric Plant in Service	2,160,321	2,019,721
Nonelectric Operations	231,135	228,120
Construction Work in Progress	49,054	181,626
Total Gross Plant	2,440,510	2,429,467
Less Accumulated Depreciation and Amortization	861,401	848,369
Net Plant	1,579,109	1,581,098
Total Assets	2,104,548	2,052,517
Liabilities and Equity
Short-Term Debt	43,601	18,599
Current Maturities of Long-Term Debt	174	172
Accounts Payable	100,496	96,291
Accrued Salaries and Wages	15,139	24,857
Accrued Federal and State Income Taxes	2,459
Other Accrued Taxes	18,590	17,287
Regulatory Liabilities	7,787	738
Current Operating Lease Liabilities	3,900
Other Accrued Liabilities	8,575	12,149
Total Current Liabilities	200,721	170,093
Pensions Benefit Liability	88,223	98,358
Other Postretirement Benefits Liability	72,456	71,561
Long-Term Operating Lease Liabilities	17,160
Other Noncurrent Liabilities	26,354	24,326
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	121,863	120,976
Deferred Tax Credits	19,637	19,974
Regulatory Liabilities	225,496	226,469
Other	2,117	1,895
Total Deferred Credits	369,113	369,314
Capitalization
Long-Term Debt—Net	590,022	590,002
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2019—39,729,708 Shares; 2018—39,664,884 Shares	198,649	198,324
Premium on Common Shares	342,991	344,250
Retained Earnings	203,619	190,433
Accumulated Other Comprehensive Loss	(4,760)	(4,144)
Total Common Equity	740,499	728,863
Total Capitalization	1,330,521	1,318,865
Total Liabilities and Equity	2,104,548	2,052,517
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares

XML

Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
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)	39,729,708	39,664,884
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 (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating Revenues:
Total Operating Revenues	$ 245,972	$ 241,266
Operating Expenses
Production Fuel – Electric	18,920	18,706
Electric Operation and Maintenance Expenses	38,382	39,475
Cost of Products Sold (depreciation included below)	90,582	88,785
Other Nonelectric Expenses	13,477	12,494
Depreciation and Amortization	19,131	18,763
Property Taxes – Electric	3,959	3,835
Total Operating Expenses	206,403	203,651
Operating Income	39,569	37,615
Interest Charges	7,826	7,372
Nonservice Cost Components of Postretirement Benefits	1,035	1,417
Other Income	1,244	1,183
Income Before Income Taxes	31,952	30,009
Income Tax Expense	5,628	3,794
Net Income	$ 26,324	$ 26,215
Average Number of Common Shares Outstanding—Basic (in shares)	39,657,321	39,550,874
Average Number of Common Shares Outstanding—Diluted (in shares)	39,903,165	39,863,682
Basic Earnings Per Common Share (in dollars per share)	$ 0.66	$ 0.66
Diluted Earnings Per Common Share (in dollars per share)	$ 0.66	$ 0.66
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 129,144	$ 123,825
Changes in Accrued Revenues under Alternative Revenue Programs	(1,049)	(875)
Total Electric Revenues	128,095	122,950
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	117,877	118,316
Electricity, Purchased [Member]
Operating Expenses
Purchased Power – Electric System Use	$ 21,952	$ 21,593

XML

Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net Income	$ 26,324	$ 26,215
Unrealized Gains (Losses) on Available-for-Sale Securities:
Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period		(110)
Unrealized Gains (Losses) Arising During Period	91	(66)
Income Tax (Expense) Benefit	(19)	37
Change in Unrealized Losses/Gains on Available-for-Sale Securities – net-of-tax	72	(139)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	130	227
Income Tax Expense	(34)	(59)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act		(531)
Pension and Postretirement Benefit Plans – net-of-tax	96	(363)
Total Other Comprehensive Income (Loss)	168	(502)
Total Comprehensive Income	$ 26,492	$ 25,713

XML

Consolidated Statements of Common Shareholders' Equity (Unaudited) - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Total
Balance (in shares) at Dec. 31, 2017	39,557,491
Balance at Dec. 31, 2017	$ 197,787	$ 343,450	$ 161,286	$ (5,631)	$ 696,892
Common Stock Issuances, Net of Expenses (in shares)	127,598
Common Stock Issuances, Net of Expenses	$ 638	(638)
Common Stock Retirements (in shares)	(58,495)
Common Stock Retirements	$ (292)	(2,117)			(2,409)
Net Income			26,215		26,215
Other Comprehensive Income (Loss)				(502)	(502)
Employee Stock Incentive Plan Expense		1,146			1,146
Common Dividends			(13,292)		(13,292)
Balance (in shares) at Mar. 31, 2018	39,626,594
Balance at Mar. 31, 2018	$ 198,133	341,841	174,209	(6,133)	708,050
Balance (in shares) at Dec. 31, 2018	39,664,884
Balance at Dec. 31, 2018	$ 198,324	344,250	190,433	(4,144)	728,863
Common Stock Issuances, Net of Expenses (in shares)	120,048
Common Stock Issuances, Net of Expenses	$ 601	(601)
Common Stock Retirements (in shares)	(55,224)
Common Stock Retirements	$ (276)	(2,454)			(2,730)
Net Income			26,324		26,324
Other Comprehensive Income (Loss)				168	168
ASU 2018-02 2017 TCJA Stranded Tax Transfer			784	(784)
Employee Stock Incentive Plan Expense		1,796			1,796
Common Dividends			(13,922)		(13,922)
Balance (in shares) at Mar. 31, 2019	39,729,708
Balance at Mar. 31, 2019	$ 198,649	$ 342,991	$ 203,619	$ (4,760)	$ 740,499

XML

Consolidated Statements of Common Shareholders' Equity (Unaudited) (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Retained Earnings [Member]
Dividends Declared Per Common Share (in dollars per share)	$ 0.35
Dividends Declared Per Common Share (in dollars per share)		$ 0.335

XML

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows from Operating Activities
Net Income	$ 26,324	$ 26,215
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization	19,131	18,763
Deferred Tax Credits	(337)	(354)
Deferred Income Taxes	835	2,901
Change in Deferred Debits and Other Assets	1,464	6,295
Discretionary Contribution to Pension Plan	(10,000)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	8,787	(5,091)
Allowance for Equity/Other Funds Used During Construction	(330)	(638)
Stock Compensation Expense—Equity Awards	1,796	1,146
Other—Net	375	(284)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(37,086)	(25,047)
Change in Inventories	(462)	35
Change in Other Current Assets	128	2,334
Change in Payables and Other Current Liabilities	4,088	(2,798)
Change in Interest and Income Taxes Receivable/Payable	2,437	1,163
Net Cash Provided by Operating Activities	17,150	4,640
Cash Flows from Investing Activities
Capital Expenditures	(24,687)	(23,618)
Net Proceeds from Disposal of Noncurrent Assets	509	510
Cash Used for Investments and Other Assets	(1,258)	(719)
Net Cash Used in Investing Activities	(25,436)	(23,827)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	8	2,338
Net Short-Term Borrowings (Repayments)	25,002	(82,052)
Payments for Retirement of Capital Stock	(2,730)	(2,409)
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	(42)	(60)
Dividends Paid	(13,922)	(13,292)
Net Cash Provided by Financing Activities	8,316	4,092
Net Change in Cash and Cash Equivalents	30	(15,095)
Cash and Cash Equivalents at Beginning of Period	861	16,216
Cash and Cash Equivalents at End of Period	$ 891	$ 1,121

XML

Note 1 - Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Significant Accounting Policies and New Accounting Pronouncements [Text Block]

1.

Summary of Significant Accounting Policies

Revenue Recognition

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. 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU)

No.

2014

-

09,

Revenue from Contracts with

Customers

(Topic

606

)

(ASC

606

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

980,

Reg

ul

ated 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 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). These revenues account for over

80%

of other electric revenues reported in the table of disaggregated revenues in note

2.

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 has recovered costs and earned 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 riders.

● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) 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 net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery 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, 2019,

and

2018.

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 customer 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. For revenue recognized on products when shipped, the operating companies have

no

further obligation to provide services related to such products. 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. 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

for a disaggregation of the Company’s revenues by business segment for the

three

-month periods ended

March 31, 2019

and

2018.

Agreements Subject to Legally Enforceable Netting Arrangements

OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The 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, 2019

and

December 31, 2018:

March 31, 201 9 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,444
Corporate Debt Securities – Held by Captive Insurance Company			$	5,975
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,644
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		1,396
Total Assets	$	2,840	$	7,619

December 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,294
Corporate Debt Securities – Held by Captive Insurance Company			$	5,898
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,586
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		838
Total Assets	$	2,132	$	7,484

The level

2

fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company 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, 2019

could be as high as

$53.1

 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)	2019		2018
Finished Goods	$	35,771	$	37,130
Work in Process		20,503		20,393
Raw Material, Fuel and Supplies		50,458		48,747
Total Inventories	$	106,732	$	106,270

Goodwill and Other Intangible Assets

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

December 31, 2018

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

2019:

(in thousands)	Gross Balance December 31, 2018		Accumulated Impairments		Balance (net of impairments) December 31, 2018		Adjustments to Goodwill in 2019		Balance (net of impairments) March 31, 2019
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, 2019

and

December 

31,

 

2018:

March 31, 201 9 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,410	$	12,081	9	-	197
Other		154		81		73		17
Total	$	22,645	$	10,491	$	12,154

December 31, 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,127	$	12,364	12	-	200
Other		154		68		86		20
Total	$	22,645	$	10,195	$	12,450

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Amortization Expense – Intangible Assets	$	296	$	345

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

five

years is:

(in thousands)	2019		2020		2021		2022		2023
Estimated Amortization Expense – Intangible Assets	$	1,184	$	1,133	$	1,099	$	1,099	$	1,099

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2019		2018
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	4,338	$	10,451

New Accounting Standards Adopted

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 supersedes the requirements under ASC Topic

840

on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU

2016

-

02

are effective for fiscal years beginning after

December 15, 2018,

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

2016

-

02

to its consolidated financial statements effective

January 1, 2019.

See note

8

for further information on leases and the Company’s elections for applying the new standard.

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/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the 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. 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 adopted the updates in ASU

2018

-

02

effective

January 1, 2019,

applying them in the period of adoption and

not

retrospectively. On adoption, the Company reclassified

$784,000

of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates.

Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below.

(in thousands)	Unrealized Gains on Available-for- Sale Securities		Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits			AOCI/(L)
Balance on December 22, 2017 – Pre-tax	$	71	$	(5,672	)	$	(5,601	)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$	10	$	(794	)	$	(784	)

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.

The Company early adopted the amendments in ASU

2017

-

04

in the

first

quarter of

2019.

The Company had

no

indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had

no

impact on the Company’s consolidated financial statements.

XML

Note 2 - Business Segment Information

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Segment Reporting Disclosure [Text Block]

2.

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 maker. 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, material handling components and extruded raw material stock. 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. 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.

While

no

single customer accounted for over

10%

of the Company’s consolidated revenue in

2018,

certain customers provided a significant portion of each business segment’s

2018

revenue. The Electric segment has

one

customer that provided

11.2%

of

2018

segment revenues. The Manufacturing segment has

one

customer that manufactures and sells recreational vehicles that provided

22.2%

of

2018

segment revenues and

one

customer that manufactures and sells lawn and garden equipment that provided

11.2%

of

2018

segment revenues. The Manufacturing segment’s top

five

revenue-generating customers provided over

52%

of

2018

segment revenues. The Plastics segment has

two

customers that together provided

39.1%

of

2018

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

99.0%

and

98.3%

of its operating revenues for the respective

three

-month periods ended

March 31, 2019

and

2018

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,

2019

and

2018

and total assets by business segment as of

March 31, 2019

and

December 

31,

2018

are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	114,955		$	109,180
Changes in Accrued ARP Revenues		(1,049	)		(875	)
Total Retail Sales Revenue		113,906			108,305
Transmission Services Revenue		10,862			11,903
Wholesale Revenues – Company Generation		1,527			1,015
Other Revenues		1,814			1,742
Total Electric Segment Revenues		128,109			122,965
Manufacturing Segment:
Metal Parts and Tooling		66,724			56,927
Plastic Products and Tooling		9,045			10,235
Other		2,053			1,500
Total Manufacturing Segment Revenues		77,822			68,662
Plastics Segment – Sale of PVC Pipe Products		40,058			49,653
Intersegment Eliminations		(17	)		(14	)
Total	$	245,972		$	241,266

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Electric	$	6,641	$	6,390
Manufacturing		584		554
Plastics		149		150
Corporate and Intersegment Eliminations		452		278
Total	$	7,826	$	7,372

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	4,771		$	2,098
Manufacturing		1,454			1,223
Plastics		1,329			2,414
Corporate		(1,926	)		(1,941	)
Total	$	5,628		$	3,794

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	18,700		$	16,668
Manufacturing		4,842			4,164
Plastics		3,729			6,844
Corporate		(947	)		(1,461	)
Total	$	26,324		$	26,215

Identifiable Assets

	March 31,		December 31,
(in thousands)	2019		2018
Electric	$	1,737,278	$	1,728,534
Manufacturing		217,390		187,556
Plastics		104,544		91,630
Corporate		45,336		44,797
Total	$	2,104,548	$	2,052,517

XML

Note 3 - Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2019

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 are expected to 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

2019

and

2018.

Major Capital Expenditure Projects

Astoria Station

—OTP is constructing this

245

-megawatt (MW) simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota 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.

A final order granting an Advance Determination of Prudence (ADP) for Astoria Station was issued by the NDPSC on

November 3, 2017,

subject to certain qualifications and compliance obligations. On

August 3, 2018

the SDPUC issued an order granting a site permit for Astoria Station. In a

September 26, 2018

hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. The interconnection agreement for Astoria Station was executed by MISO in

December 2018

and accepted by the FERC in

January 2019.

As of

March 31, 2019,

OTP had capitalized approximately

$7.7

million in development and other costs associated with Astoria Station.

Merricourt Project

—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 and certain specified liabilities associated with a

150

-MW wind farm in southeastern North Dakota (the Merricourt Project) for a purchase price of approximately

$34.7

 million, subject to adjustments for interconnection costs. The Purchase Agreement will close on satisfaction of various closing conditions (including regulatory approvals). Also on

November 16, 2016,

OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement with EDF pursuant to which EDF will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in

2020

for consideration of approximately

$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 customary representations, warranties, covenants and indemnities for this type of transaction. 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, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on

January 10, 2018.

A final order for an ADP, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on

November 3, 2017.

The Merricourt generation interconnection agreement with MISO was approved by the FERC in

April 2019.

Construction of the Merricourt Project will begin after closing on the Purchase Agreement, anticipated to occur in the last half of

2019.

As of

March 

31,

2019,

OTP had capitalized approximately

$5.3

million in development costs associated with the Merricourt Project.

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

—This

345

-kilovolt transmission line, energized on

February 6, 2019,

extends

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., and the parties have equal ownership interest in the transmission line portion of the project. The 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 MISO 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. OTP’s capitalized costs on this project as of

March 31, 2019

were approximately

$106

 million, which includes assets that are

100%

owned by OTP.

Recovery of OTP’s major transmission investments is through the MISO Tariff and, currently, Minnesota, North Dakota and South Dakota base rates and 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 is

8.61%

and its allowed rate of return on equity (ROE) is

10.74%.

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 (see discussion under Minnesota Transmission Cost Recovery Rider below), and (

2

) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, which occurred when final rates were implemented on

November 1, 2017.

Certain MISO expenses and revenues remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

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 changes to the MNCIP financial incentive. The model included incentives for utilities 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 was also limited to

40%

of

2017

MNCIP spending and

35%

of

2018

spending and will be limited to

30%

of

2019

spending. The new model reduces the MNCIP financial incentive by approximately

50%

compared to the previous incentive mechanism. The Minnesota Department of Commerce (MNDOC) issued a proposed decision on

March 20, 2019

to extend all utilities

2017

-

2019

CIP plans

one

year, through

2020.

 

On

April 1, 2019

OTP filed a request for approval of its

2018

energy savings, recovery of

$3.0

million in accrued financial incentives and recovery of

2018

program costs

not

included in base rates.

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 MVPs 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 diverted 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 resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision would 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

June 11, 2018

the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On

July 11, 2018

the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. Oral arguments were heard by the Minnesota Supreme Court on

March 11, 2019.

On

November 30, 2018

OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing

two

scenarios were submitted based on whether the Minnesota Supreme Court affirms the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturns the Minnesota Court of Appeals decision and includes the

two

MVP projects in the TCR rider. Action by the Minnesota Supreme Court is expected later in

2019,

increasing the likelihood the MPUC will delay its decision on the TCR rider update. In addition, on

April 1, 2019,

the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The estimated amount credited to Minnesota customers through the TCR rider through

March 31, 2019

is approximately

$2.5

 million.

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.

Accordingly, in its

2018

annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to

zero

effective

December 1, 2018.

The remaining under-recovered balance was charged on customer billings in

March

and

April 2019.

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 requested

$13.1

million increase was net of reductions in North Dakota RRA, TCR and ECR rider revenues that would have resulted from a lower allowed rate of ROE 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 ROE of

10.3%.

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.

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 included

$4.8

 million related to tax reform and

$1.2

 million related to other updates.

In a

September 26, 2018

hearing the NDPSC approved an overall annual revenue increase of

$4.6

million (

3.1%

) and a ROE of

9.77%

on a

52.5%

equity capital structure. This compares with OTP’s

March 2018

adjusted annual revenue increase request of

$7.1

million (

4.8%

) and a requested ROE of

10.3%.

The NDPSC’s approval does

not

require any rate base adjustments from OTP’s original request and establishes a GCR rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements related to the TCJA and decreases in rider revenue recovery requirements. Final rates were effective

February 1, 2019,

with refunds of excess revenues collected under interim rates applied to customers’

April 2019

bills. OTP has accrued an interim rate refund of

$3.4

 million as of

March 31, 2019,

which includes interest and

$0.8

million in excess revenue collected for income taxes under interim rates in effect in

January

and

February 2018.

Renewable Resource Adjustment

—OTP has a North Dakota RRA 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.

Effective in

February 2019

with the implementation of general rates based on the results of OTP’s

2017

general rate case, recovery of renewable resource costs previously being recovered through the North Dakota RRA rider transitioned to recovery in base rates.

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. Based on the order in the

2017

general rate case, only certain costs will remain subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule

26

and

26A

revenues and expenses and costs related to rider projects still under construction in the test year used in the

2017

general rate case. This rider will continue to be updated annually for new or modified electric transmission facilities and associated operating costs.

Environmental Cost Recovery Rider

—OTP has an ECR rider in North Dakota. The ECR rider has provided for a return on investment at the level approved in OTP’s preceding general rate case and for recovery of OTP’s North Dakota share of environmental investments and costs approved for recovery under the rider. Prior to its

2017

general rate case reaching a final settlement and final rates going into effect on

February 1, 2019,

OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were being recovered through the ECR rider. Effective

February 1, 2019

these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to ratepayers through the rider.

Generation Cost Recovery Rider

—On

March 1, 2019

OTP filed a request with the NDPSC to establish an initial GCR rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements of its investment in Astoria Station.

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. Interim rates went into effect

October 

18,

2018.

The

second

step in the request was an additional

1.7%

revenue increase to recover costs for the proposed Merricourt wind generation facility when the facility goes into service.

The SDPUC approved a partial settlement on

March 1, 2019

on all issues of the rate case except ROE. The settlement includes approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and the Merricourt Project, which addresses the

second

step of the request for increased rates in South Dakota. The partial settlement also includes a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The settlement also allows OTP to retain the impact of lower tax rates related to the TCJA from

January 1, 2018

through

October 17, 2018

resulting in the reversal of an accrued refund liability and recognition of

$1.0

 million in revenue in the

first

quarter of

2019.

OTP expects a final determination on its allowed rate of ROE sometime during the

second

quarter of

2019.

OTP’s previously approved general rate increase in South Dakota of approximately

$643,000

or approximately

2.32%

was granted by the SDPUC in an order issued in

April 2011

and effective in

June 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. OTP has a TCR rider in South Dakota. A supplemental filing to update the rider was made on

January 29, 2018

to reflect updated costs and collections and incorporate the impact of the reduction in the federal corporate income tax rate under the TCJA. Effective

October 18, 2018,

with the implementation of interim rates under South Dakota general rate case proceedings, the TCR rate was decreased as a result of recovery of certain costs being shifted to recovery in interim rates and proposed for ongoing recoveries in final base rates at the end of the

2018

general rate case.

OTP made a supplemental filing for the South Dakota TCR rider on

February 1, 2019.

On

February 8, 2019

the SDPUC approved the supplemental filing and rates effective

March 1, 2019.

Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective

January 1, 2019

and The Big Stone South – Ellendale project with a recovery date effective

January 2020.

Environmental Cost Recovery Rider

—OTP has an ECR rider in South Dakota. 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 South Dakota share of environmental investments and costs approved for recovery under the rider. Prior to interim rates going into effect on

October 18, 2018

pending a final decision on OTP’s South Dakota general rate increase request, OTP’s South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxics Standards projects were being recovered through the ECR rider. With the initiation of interim rates, recovery of the costs previously being recovered under the ECR rider was transitioned to recovery under interim rates and the South Dakota ECR rider rate was reset to provide a refund to customers while interim rates are in effect.

Rate Rider Updates

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

January 1, 2017

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
2018 Incentive and Cost Recovery	R – April 1, 2019	October 1, 2019	$	11,926		$0.00710/kwh
2017 Incentive and Cost Recovery	A – October 4, 2018	November 1, 2018	$	10,283		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
Transmission Cost Recovery
2018 Annual Update–Scenario A	R – November 30, 2018	June 1, 2019	$	6,475		Various
–Scenario B			$	2,708		Various
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
Environmental Cost Recovery
2018 Annual Update	A – November 29, 2018	December 1, 2018	$	--		0% of base
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
Renewable Resource Adjustment
2018 Annual Update	A – August 29, 2018	November 1, 2018	$	5,886		$.00244/kwh
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2019 Annual Update	A – May 1, 2019	June 1, 2019	$	(235	)	-0.224% of base
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
Transmission Cost Recovery
2018 Supplemental Update	A – December 6, 2018	February 1, 2019	$	4,801		Various
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
Environmental Cost Recovery
2018 Update	A – December 19, 2018	February 1, 2019	$	(378	)	-0.310% of base
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
Generation Cost Recovery
2019 Initial Request	R – March 1, 2019	July 1, 2019	$	2,720		2.547% of base
South Dakota
Transmission Cost Recovery
2019 Annual Update	A – February 20, 2019	March 1, 2019	$	1,638		Various
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	1,171		Various
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
Environmental Cost Recovery
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	(189	)	-$0.00075/kwh
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh

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)	2019			2018
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,152		$	2,516
Renewable Resource Recovery		1,316			525
Transmission Cost Recovery		641			(29	)
Environmental Cost Recovery		(1	)		(31	)
North Dakota
Transmission Cost Recovery		1,772			2,062
Renewable Resource Adjustment		729			1,967
Environmental Cost Recovery		575			1,821
Generation Cost Recovery		248			--
South Dakota
Transmission Cost Recovery		473			536
Conservation Improvement Program Costs and Incentives		244			229
Environmental Cost Recovery		(4	)		520
Total	$	8,145		$	10,116

1

Includes MNCIP costs recovered in base rates.

TCJA

The TCJA, passed in

December 2017,

reduced the federal corporate income tax rate from

35%

to

21%,

effective

January 1, 2018.

At the time of passage, OTP’s electric rates had been developed using a

35%

tax rate. The MPUC, the NDPSC, the SDPUC and the FERC each initiated dockets or proceedings to begin working with utilities to assess the impact of the lower rates on electric rates, and to develop regulatory strategies to incorporate the tax reduction into future electric rates, if warranted.

The MPUC required regulated utilities providing service in Minnesota to make filings by

February 15, 2018.

On

August 9, 2018

the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. On

December 5, 2018

the MPUC issued its final order related to the TCJA docket directing OTP to return to ratepayers, in a

one

-time refund, the TCJA-related savings accrued prior to the refund effective date. OTP must amortize its protected excess accumulated deferred income taxes (ADIT) as early as U.S. Internal Revenue Service provisions allow and amortize its unprotected excess ADIT over

ten

years. OTP was instructed to use its

2017

year-end ADIT balance to calculate its excess ADIT balance. The order also directs OTP to use these savings to reduce customers’ base rates prospectively—allocating the savings to customers in proportion to the size of each customer’s bill, or to each customer class in proportion to the class’s size. OTP expects the rate change to occur in the

second

quarter of

2019

and a

one

-time refund to occur in the

third

quarter of

2019,

pending MPUC approval of OTP’s

January 3, 2019

compliance filing.

As described above, OTP’s current general rate cases in North Dakota and South Dakota reflect the ongoing impact of the TCJA in interim rates. OTP has accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurs under the lower federal tax rates in the TCJA. As of

March 

31,

2019,

accrued refund liabilities related to the tax rate reduction were

$10.4

 million in Minnesota,

$0.8

million in North Dakota for amounts collected reflecting the higher tax rates under interim rates in effect in

January

and

February 2018,

and

$0.3

 million for FERC jurisdictional rates. The North Dakota liability was refunded with the interim rate refund in

April 2019.

As of

March 15, 2018,

the FERC granted the request for waiver from a group of MISO transmission operators (including OTP) to revise inputs to their projected net revenue requirements for the

2018

rate year to reflect recent tax law changes.

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of

1935

(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 suspension period, subject to ultimate approval by the FERC.

MVPs

—MVPs are designed to enable the MISO 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%.

Several 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 went to

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, 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, 2019.

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 U.S. 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. The motion is currently pending before the FERC.

On

October 16, 2018

the FERC issued an order proposing a methodology for addressing the issues that were remanded to the FERC by the D.C. Circuit in

April 2017.

The FERC order established a paper hearing on how the methodology should apply to the proceedings pending before the FERC involving NETOs’ ROE. In the order, the FERC selected a preliminary just and reasonable ROE for NETOs of

10.41%,

exclusive of incentives, with a proposed cap on any pre-existing incentive-based total ROE at

13.08%

and directed participants to submit supplemental briefs and additional written evidence regarding the proposed approaches to the Federal Power Act Section

206

inquiry and how to apply them to the NETO ROE complaints. On

November 15, 2018,

FERC issued an order establishing a paper hearing on whether and how a

two

-step ROE methodology developed for NETOs should apply to the ROE for MISO transmission owners. Initial briefs were due

February 13, 2019

and reply briefs were due

April 10, 2019.

FERC is under

no

statutory timeline to act; however, the Company expects FERC to issue an order in the

third

or

fourth

quarter of

2019.

OTP believes its estimated accrued MISO Tariff ROE refund liability of

$1.6

million as of

March 31, 2019

related to the

second

MISO tariff ROE complaint is appropriate.

XML

Note 4 - Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2019

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

980.

This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC

980

-

605

-

25

provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	March 31, 2019								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	$	6,355	$	116,835		$	123,190		see below
Accumulated ARO Accretion/Depreciation Adjustment 1		--		7,302			7,302		asset lives
Conservation Improvement Program Costs and Incentives 2		3,007		3,979			6,986			18
Deferred Marked-to-Market Losses 1		1,432		557			1,989			21
Minnesota Transmission Cost Recovery Rider Accrued Revenues 2		1,958		--			1,958			12
Deferred Income Taxes 1		--		1,557			1,557		asset lives
Big Stone II Unrecovered Project Costs – Minnesota 1		689		770			1,459			25
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		1,143			1,143		asset lives
Debt Reacquisition Premiums 1		203		701			904			162
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		416		--			416			12
Big Stone II Unrecovered Project Costs – South Dakota 1		117		292			409			42
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		180		130			310			33
South Dakota Deferred Rate Case Expenses Subject to Recovery 1		267		--			267			12
North Dakota Generation Cost Recovery Rider Accrued Revenues 2		248		--			248			12
Recoverable Fuel and Purchased Power Costs – South Dakota 1		197		--			197			12
Minnesota SPP Transmission Cost Recovery Tracker 1		--		117			117		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		52		--			52			4
Deferred Lease Expenses 1		--		44			44			48
Minnesota Environmental Cost Recovery Rider Accrued Revenues 2		38		--			38			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues 2		34		--			34			12
Total Regulatory Assets	$	15,193	$	133,427		$	148,620
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	141,452		$	141,452		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,555			83,555		asset lives
Refundable Fuel Clause Adjustment Revenues – Minnesota		5,149		--			5,149			12
North Dakota Renewable Resource Recovery Rider Accrued Refund		901		--			901			12
North Dakota Environmental Cost Recovery Rider Accrued Refund		669		--			669			12
Refundable Fuel Clause Adjustment Revenues – North Dakota		537		--			537			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		272		--			272			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		225			225		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			21
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		103		--			103			12
Other		5		77			82			177
Total Regulatory Liabilities	$	7,787	$	225,496		$	233,283
Net Regulatory Asset/(Liability) Position	$	7,406	$	(92,069	)	$	(84,663	)

1

Costs subject to recovery without a rate of return.

2

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

	December 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	$	6,346	$	118,433		$	124,779		see below
Accumulated ARO Accretion/Depreciation Adjustment 1		--		7,169			7,169		asset lives
Conservation Improvement Program Costs and Incentives 2		5,995		3,285			9,280			21
Deferred Marked-to-Market Losses 1		1,661		743			2,404			24
Minnesota Transmission Cost Recovery Rider Accrued Revenues 2		444		--			444			12
Deferred Income Taxes 1		--		2,423			2,423		asset lives
Big Stone II Unrecovered Project Costs – Minnesota 1		681		947			1,628			28
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		986			986		asset lives
Debt Reacquisition Premiums 1		207		753			960			165
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		455		--			455			12
Big Stone II Unrecovered Project Costs – South Dakota 1		100		342			442			53
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		240		--			240			12
South Dakota Deferred Rate Case Expenses Subject to Recovery 1		178		--			178			12
Minnesota SPP Transmission Cost Recovery Tracker 1		--		176			176		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		328		--			328			4
Minnesota Environmental Cost Recovery Rider Accrued Revenues 2		121		--			121			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues 2		452		--			452			12
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		17		--			17			12
Total Regulatory Assets	$	17,225	$	135,257		$	152,482
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	142,779		$	142,779		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,229			83,229		asset lives
North Dakota Renewable Resource Recovery Rider Accrued Refund		177		--			177			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		166			166		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			24
South Dakota Transmission Cost Recovery Rider Accrued Refund		168		--			168			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		207		--			207			12
Refundable Fuel Clause Adjustment Revenues		121		--			121			12
Other		5		108			113			180
Total Regulatory Liabilities	$	738	$	226,469		$	227,207
Net Regulatory Asset/(Liability) Position	$	16,487	$	(91,212	)	$	(74,725	)

1

Costs subject to recovery without a rate of return.

2

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

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.

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

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

All Deferred Marked-to-Market Losses recorded as of

March 31, 2019

relate to forward purchases of energy scheduled for delivery through

December 2020.

The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of

March 31, 2019.

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

740,

Income Taxes

.

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.

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.

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

162

months.

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

January 2018.

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.

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.

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

October 2018.

North Dakota Generation Cost Recovery (NDGCR) Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The

March 31, 2019

balance represents amounts subject to recovery from North Dakota customers that have

not

been billed to North Dakota customers. The NDGCR is expected to go into effect in

July 2019

pending NDPSC review and approval.

The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have

not

been billed to Minnesota customers as of

March 31, 2019.

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.

Deferred Lease Expenses: Under ASC

842

accounting rules, for leases with scheduled escalating payments, rent expense is required to be recognized on a straight-line basis over the life of the lease based on the sum of those payments. Rate-regulated entities are generally only allowed to recover the amount of actual cash payments on leases and FERC accounting rules require that rent expense be recognized on the basis of cash payments. The balance in the deferred lease expense regulatory asset account on

March 31, 2019

represents operating lease right of use asset cumulative amortization and interest costs in excess of cumulative lease payments that are subject to recovery in future periods under regulatory account treatment as cash payments are rendered.

The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are recoverable from Minnesota customers as of

March 31, 2019.

The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of

March 31, 2019.

Currently, the rider is only being used to recover the amount of federal PTCs generated by OTP’s wind farms that were transferred from inclusion in the rider and applied as a reduction in revenue requirements to Minnesota base rates. Subsequent to applying the PTCs to base rates the PTCs expired. The Minnesota RRA rider is now being used to recover the shortfall in 

base rates related to the expiration of the PTCs. Recovery will continue through the rider until interim or revised base rates are established in connection with OTP’s next Minnesota rate case.

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 are recoverable from North Dakota customers as of

March 31, 2019.

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

North Dakota Renewable Resource Recovery 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, 2019.

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

March 31, 2019.

Effective

February 1, 2019

these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to Minnesota ratepayers through the rider.

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, 2019.

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.

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, 2019.

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, 2019.

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 - Common Shares and Earnings Per Share

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Stockholders Equity and Earnings per Share [Text Block]

5.

Common Shares and Earnings Per Share

Shelf Registration

On

May 3, 2018

the Company filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which the Company

may

offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on

May 3, 2021.

Common Shares

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

December 31, 2018

through

March 31, 2019:

Common Shares Outstanding, December 31, 2018	39,664,884
Issuances:
Executive Stock Performance Awards (2016 shares earned)	102,198
Vesting of Restricted Stock Units	17,850
Retirements:
Shares Withheld for Individual Income Tax Requirements	(55,224	)
Common Shares Outstanding, March 31, 2019	39,729,708

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, 2019

and

2018.

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:

	2019		2018
Weighted Average Common Shares Outstanding – Basic		39,657,321		39,550,874
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		158,159		223,162
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		63,398		59,130
Nonvested Restricted Shares		21,922		27,643
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,365		2,873
Total Dilutive Shares		245,844		312,808
Weighted Average Common Shares Outstanding – Diluted		39,903,165		39,863,682

The effect of dilutive shares on earnings per share for the

three

-month periods ended

March 31, 2019

and

2018,

resulted in

no

differences greater than

$0.01

between basic and diluted earnings per share in either period.

XML

Note 6 - Share-based Payments

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Share-based Payment Arrangement [Text Block]

6.

Share-Based Payments

Stock Incentive Awards

On

February 13, 2019

the following stock incentive awards were granted under the

2014

Stock Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant- Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,600	$	49.6225	25% per year through February 6, 2023
Stock Performance Awards Granted:
Under Executive and Select Employee Agreements		47,800	$	42.875	December 31, 2021
Under Legacy Agreement		7,800	$	45.885	December 31, 2021

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

55,600

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

27,800

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

3

-year average adjusted ROE. The participants would also earn an aggregate of

27,800

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, 2019

through

December 31, 2021,

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, 2019

and the average closing price for the

20

trading days immediately preceding

January 1, 2022.

Actual payment

may

range from

zero

to

150%

of the target amount, or up to

83,400

common shares. There are

no

voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC Topic

718,

Compensation

– Stock Compensation

, 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.

Under the

2019

Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to 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 vesting of these awards is accelerated and paid at target in the event of a change in control.

The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier 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, 2019,

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

$6.2

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 stock-based payment programs for the

three

-month periods ended

March 31, 2019

and

2018

are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2019		2018
Stock Performance Awards Granted to Executive Officers	$	1,113	$	651
Restricted Stock Units Granted to Executive Officers		427		249
Restricted Stock Granted to Executive Officers		--		16
Restricted Stock Granted to Directors		165		166
Restricted Stock Units Granted to Non-Executive Employees		91		64
Totals	$	1,796	$	1, 146

XML

Note 7 - Retained Earnings and Dividend Restriction

3 Months Ended

Mar. 31, 2019

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, 2019,

the Company was in compliance with these financial 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

47.9%

and

58.5%

based on OTP’s

2018

capital structure petition effective by order of the MPUC on

October 18, 2018.

As of

March 31, 2019,

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

53.2%

and its net assets restricted from distribution totaled approximately

$484

million. Total capitalization for OTP cannot currently exceed

$1.2

 billion.

XML

Note 8 - Leases

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Lessee, Operating Leases [Text Block]

8.

Leases

 

The Company adopted ASU

2016

-

02

and related updates (ASC Topic

842

), which replaced previous lease accounting guidance, on

January 1, 2019,

using the modified retrospective method of adoption. As a result, prior periods have

not

been restated. ASC Topic

842

requires lessees to record assets and liabilities on the balance sheet for all leases with terms longer than

12

months. Adoption of the standard resulted in the recognition of net lease assets and lease liabilities of

$20

 million on

January 1, 2019.

The adoption of the new standard did

not

have a material effect on the Company’s consolidated statements of income or cash flows. In addition, the adoption did

not

have a material impact on the Company’s liquidity or the Company’s covenant compliance under its current debt agreements.

The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic

840.

The Company also elected the practical expedient related to land easements, allowing for the continuation of historical accounting treatment for land easements on existing agreements at OTP. In addition, the Company has elected the hindsight practical expedient to determine the reasonably certain lease term for leases in place at the time of adoption. The Company has elected the practical expedient to

not

separate nonlease components from lease components on real estate leases for the purpose of determining the classification and the value of lease assets and lease liabilities at the inception of a lease.

The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than

one

year to approximately

10

years. If a lease contains an option to extend and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception.

None

of these leases met the criteria to be classified as financing leases. Of the operating leases in place on

January 1, 2019,

50

were capitalized as right-of-use assets the remainder were month-to-month leases with

no

long-term obligations.

The right-of-use asset operating leases in place at the time of adoption were capitalized on the basis of their remaining payment obligation balances, discounted to present value based on the Company’s incremental borrowing rates (IBRs) appropriate to the leased asset and lease terms. The remaining payments for operating lease right-of-use assets are being charged to expense on a straight-line basis over the life of the lease.

For the Company’s current lease obligations,

no

explicit interest rates were stated in the lease agreements and

no

implicit rates could be determined based on the terms of the agreements. Therefore, in all cases, the Company has applied a formula-based IBR appropriate to the individual company, type of lease and lease term. 

The breakdown of right-of-use assets and lease liabilities as of

March 31, 2019

by business segment is provided in the following table.

(in thousands)	Electric			Manufacturing			Plastics			Corporate			Total
Right of Use Assets – Operating Leases:
Gross	$	3,421		$	16,976		$	666		$	767		$	21,830
Accumulated Amortization		(257	)		(734	)		(97	)		(30	)		(1,118	)
Net of Accumulated Amortization	$	3,164		$	16,242		$	569		$	737		$	20,712
Obligations:
Current Operating Lease Liabilities	$	913		$	2,458		$	379		$	150		$	3,900
Long-Term Operating Lease Liabilities		2,470			13,852			190			648			17,160
Total Lease Liabilities	$	3,383		$	16,310		$	569		$	798		$	21,060

The amounts of the Company’s right-of-use operating lease obligations for each of the

five

years in the period

2019

through

2023

and in aggregate for the years beyond

2023

are presented in the following table, including obligations under lease agreements that had

not

commenced as of

March 31, 2019.

	Right-of-Use Operating Leases
(in thousands)	OTP			Nonelectric			Total
2019	$	845		$	3,078		$	3,923
2020		1,115			3,948			5,063
2021		1,091			3,657			4,748
2022		207			3,529			3,736
2023		196			3,209			3,405
Beyond 2023		447			8,023			8,470
Total Minimum Obligations	$	3,901		$	25,443		$	29,344
Interest Component of Obligations		(355	)		(4,376	)		(4,731	)
Present Value of Leases Commencing after March 31, 2019		(163	)		(3,390	)		(3,553	)
Present Value of Minimum Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

The Company’s total minimum lease obligations reported in the table above include obligations for a

ten

-year lease of a warehouse by T.O. Plastics entered into in

2018

and commencing in

July 2019

and a

27

-month lease of

20

additional coal rail cars to transport coal to OTP’s Hoot Lake Plant entered into and commencing in

April 2019.

The weighted-average remaining lease term for the Company’s outstanding lease liabilities is

6

years and the weighted-average discount rate is

5.0%.

A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic

842

on

January 1, 2019

and its operating lease obligations on

March 31, 2019

is provided in the table below.

(in thousands)	OTP			Nonelectric			Total
Operating Lease Obligations, January 1, 2019	$	3,609		$	16,760		$	20,369
Non-cash Acquisition of Right-of-Use Assets		--			1,725			1,725
Lease Obligation Payments		(270	)		(1,020	)		(1,290	)
Interest Component of Lease Obligation Payment		44			212			256
Operating Lease Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service.

The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income.

The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the

three

-month period ending

March 31, 2019

is presented in the following table.

(in thousands)	Operating Lease Cost		Variable Lease Cost		Total Lease Cost
Plant in Service or CWIP	$	9	$	--	$	9
Inventory		225		--		225
Cost of Products Sold		1,036		27		1,063
Electric Operation and Maintenance Expenses		66		--		66
Other Nonelectric Expenses		54		--		54
Total	$	1,390	$	27	$	1,417

XML

Note 9 - Commitments and Contingencies

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

9.

Commitments and Contingencies

Construction and Other Purchase Commitments

At

March 31, 2019

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

2021

of approximately

$70.5

million. At

December 31, 2018

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

2021

of approximately

$64.5

million. At

March 31, 2019

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

December 

31,

2021

of approximately

$4.7

million. At

December 31, 2018

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

December 31, 2021

of approximately

$5.0

million.

Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts

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

2042.

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

2040.

OTP’s current coal purchase agreements for Big Stone Plant expire at the end of

2020.

OTP has an agreement with Peabody COALSALES, LLC for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through

December 31, 2020.

There is

no

fixed minimum purchase requirement under this agreement but all of Big Stone Plant’s coal requirements for the period covered must be purchased under this agreement, except for a portion contracted to be purchased in

2019

under a prior existing agreement with Contura Coal Sales, LLC. OTP has an all-requirements agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through

December 31, 2023.

There are

no

fixed minimum purchase requirements under this agreement.

OTP Land Easements

OTP has commitments to make future payments for land easements

not

classified as leases, extending into

2034

of approximately

$10.8

million.

Contingencies

OTP had a

$1.6

million refund liability on its balance sheet as of

March 31, 2019

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. As discussed in note

3

in greater detail, OTP believes its estimated accrued refund liability is appropriate based on the current facts and circumstances and is awaiting further action by the FERC before determining if a change in this estimate will be needed.

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 potential ROE refund described above, the most significant contingencies that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, and litigation matters. The Company currently is

not

aware of any items that would result in charges in excess of established reserve amounts.

In

2015

the Environmental Protection Agency (EPA), acting under Section

111

(d) of the Clean Air Act, issued the Clean Power Plan which required states to submit plans to limit carbon dioxide emissions from certain fossil fuel-fired power plants. The rule is

not

currently in effect as a result of a stay by the Supreme Court in

2016.

In

2017,

the EPA issued a Notice of Proposed Rulemaking to repeal the Clean Power Plan; comments were due in

April 2018.

On

August 21, 2018

the EPA proposed a replacement for the Clean Power Plan -- the Affordable Clean Energy (ACE) Rule. Among other things, the ACE Rule determines that the best system of emission reduction for greenhouse gas emissions from coal-fired power plants is to improve the plants’ heat rates, identifies a list of “candidate technologies” for improving a plant’s heat rate and proposes that physical or operational changes to a power plant would

not

be a “major modification” triggering extensive New Source Review, if the change does increase hourly emissions. If the ACE Rule goes into effect, states will have

three

years after the final rule to submit a state implementation plan.

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, 2019

will

not

be material.

XML

Note 10 - Short-term and Long-term Borrowings

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Debt Disclosure [Text Block]

10.

Short-Term and Long-Term Borrowings

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

March 31, 2019

and

December 31, 2018:

(in thousands)	Line Limit		In Use on March 31, 2019		Restricted due to Outstanding Letters of Credit		Available on March 31, 2019		Available on December 31, 2018
Otter Tail Corporation Credit Agreement	$	130,000	$	27,742	$	--	$	102,258	$	120,785
OTP Credit Agreement		170,000		15,859		300		153,841		160,316
Total	$	300,000	$	43,601	$	300	$	256,099	$	281,101

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, 2019

and

December 31, 2018:

March 31, 201 9 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	15,859	$	27,742	$	43,601
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
PACE Note, 2.54%, due March 18, 2021				480		480
Total	$	512,000	$	80,480	$	592,480
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		174		174
Unamortized Long-Term Debt Issuance Costs		1,890		394		2,284
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,110	$	79,912	$	590,022
Total Short-Term and Long-Term Debt (with current maturities)	$	525,969	$	107,828	$	633,797

December 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	9,384	$	9,215	$	18,599
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
PACE Note, 2.54%, due March 18, 2021				523		523
Total	$	512,000	$	80,523	$	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		172		172
Unamortized Long-Term Debt Issuance Costs		1,942		407		2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,058	$	79,944	$	590,002
Total Short-Term and Long-Term Debt (with current maturities)	$	519,442	$	89,331	$	608,773

XML

Note 11 - Pension Plan and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Pension and Other Postretirement Benefits Disclosure [Text Block]

1

1

. 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)	2019			2018
Service Cost—Benefit Earned During the Period	$	1,373		$	1,615
Interest Cost on Projected Benefit Obligation		3,603			3,363
Expected Return on Assets		(5,325	)		(5,300	)
Amortization of Prior-Service Cost:
From Regulatory Asset		1			4
From Other Comprehensive Income 1		2			--
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,163			1,784
From Other Comprehensive Income 1		27			44
Net Periodic Pension Cost 2	$	844		$	1,510
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs:
Service c osts included in OTP c apital e xpenditures	$	390		$	328
Service c osts included in e lectric o peration and m aintenance e xpenses		950			1,247
Service c osts included in o ther n onelectric e xpenses		33			40
Nonservice costs capitalized as regulatory assets		(150	)		(21	)
Nonservice costs included in n onservice cost components of postretirement benefits		(379	)		(84	)

Cash flows

—The Company had

no

minimum funding requirement as of

December 31, 2018

but made a discretionary plan contribution of

$10

million in

January 2019.

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)	2019		2018
Service Cost—Benefit Earned During the Period	$	105	$	100
Interest Cost on Projected Benefit Obligation		434		399
Amortization of Prior Service Cost:
From Regulatory Asset		1		4
From Other Comprehensive Income 1		4		10
Amortization of Net Actuarial Loss:
From Regulatory Asset		31		67
From Other Comprehensive Income 1		87		165
Net Periodic Pension Cost 2	$	662	$	745
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 cost components of postretirement benefits .
2 Allocation of Costs:
Service c osts included in e lectric o peration and m aintenance e xpenses	$	26	$	25
Service costs included in ot her n onelectric e xpenses		79		75
Nonservice c osts included in n onservice cost components of postretirement benefits		557		645

Other

Postretirement Benefits

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

	Three Months Ended March 31,
(in thousands)	2019			2018
Service Cost—Benefit Earned During the Period	$	321		$	382
Interest Cost on Projected Benefit Obligation		770			645
Amortization of Net Actuarial Loss:
From Regulatory Asset		393			412
From Other Comprehensive Income 1		10			10
Net Periodic Postretirement Benefit Cost 2	$	1,494		$	1,449
Effect of Medicare Part D Subsidy	$	(45	)	$	(37	)
1 Corporate cost included in nonservice cost components of postretirement benefits.
2 Allocation of Costs:
Service c osts included in OTP capital expenditures	$	91		$	78
Service costs included in electric operation and maintenance expenses		223			294
Service costs included in other nonelectric expenses		7			10
Nonservice costs capitalized as regulatory assets		333			217
Nonservice costs included in n onservice cost components of postretirement benefits		840			850

XML

Note 12 - Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Fair Value Disclosures [Text Block]

1

2

. 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, 2019

and

December 31, 2018

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, 2019						December 31, 2018
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	891		$	891		$	861		$	861
Short-Term Debt		(43,601	)		(43,601	)		(18,599	)		(18,599	)
Long-Term Debt including Current Maturities		(590,196	)		(611,219	)		(590,174	)		(601,513	)

XML

Note 13 - Property, Plant and Equipment

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Property, Plant and Equipment Disclosure [Text Block]

13.

Property, Plant and Equipment

No

update required for interim reporting period.

XML

Note 14 - Income Tax Expense - Continuing Operations

3 Months Ended

Mar. 31, 2019

Notes to Financial Statements

Income Tax Disclosure [Text Block]

1

4

. Income Tax Expense

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

three

-month periods ended

March 31, 2019

and

2018:

	Three Months Ended March 31,
(in thousands)	2019			2018
Income Before Income Taxes	$	31,952		$	30,009
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)		8,308			7,802
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates		(983	)		(1,073	)
Excess Tax Deduction – Equity Method Stock Awards		(827	)		(624	)
Corporate Owned Life Insurance		(409	)		(8	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(258	)
Research and Development and Other Tax Credits		(188	)		(180	)
Allowance for Funds Used During Construction – Equity		(86	)		(167	)
Federal Production Tax Credits (PTCs)		--			(1,120	)
Other Comprehensive Income Deferred Tax Rate Adjustment		--			(531	)
Other Items – Net		71			(47	)
Income Tax Expense	$	5,628		$	3,794
Effective Income Tax Rate		17.6	%		12.6	%

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

(in thousands)	2019		2018
Balance on January 1	$	1,282	$	684
Increases Related to Tax Positions for Current Year		38		36
Uncertain Positions Resolved During Year		--		(44	)
Balance on March 31	$	1,320	$	676

The balance of unrecognized tax benefits as of

March 31, 2019

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

March 31, 2019

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, 2019.

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

May 1, 2019,

with limited exceptions, the Company is

no

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

2015

for federal, Minnesota and North Dakota income taxes.

XML

Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Revenue [Policy Text Block]

Revenue Recognition

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. 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 Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU)

No.

2014

-

09,

Revenue from Contracts with

Customers

(Topic

606

)

(ASC

606

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

980,

Reg

ul

ated 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 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). These revenues account for over

80%

of other electric revenues reported in the table of disaggregated revenues in note

2.

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 has recovered costs and earned 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 riders.

● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) 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 net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery 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, 2019,

and

2018.

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 customer 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. For revenue recognized on products when shipped, the operating companies have

no

further obligation to provide services related to such products. 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. 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

for a disaggregation of the Company’s revenues by business segment for the

three

-month periods ended

March 31, 2019

and

2018.

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. 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, 2019

and

December 31, 2018:

March 31, 201 9 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,444
Corporate Debt Securities – Held by Captive Insurance Company			$	5,975
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,644
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		1,396
Total Assets	$	2,840	$	7,619

December 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,294
Corporate Debt Securities – Held by Captive Insurance Company			$	5,898
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,586
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		838
Total Assets	$	2,132	$	7,484

The level

2

fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company 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, 2019

could be as high as

$53.1

 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)	2019		2018
Finished Goods	$	35,771	$	37,130
Work in Process		20,503		20,393
Raw Material, Fuel and Supplies		50,458		48,747
Total Inventories	$	106,732	$	106,270

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, 2018

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

2019:

(in thousands)	Gross Balance December 31, 2018		Accumulated Impairments		Balance (net of impairments) December 31, 2018		Adjustments to Goodwill in 2019		Balance (net of impairments) March 31, 2019
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, 2019

and

December 

31,

 

2018:

March 31, 201 9 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,410	$	12,081	9	-	197
Other		154		81		73		17
Total	$	22,645	$	10,491	$	12,154

December 31, 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,127	$	12,364	12	-	200
Other		154		68		86		20
Total	$	22,645	$	10,195	$	12,450

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Amortization Expense – Intangible Assets	$	296	$	345

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

five

years is:

(in thousands)	2019		2020		2021		2022		2023
Estimated Amortization Expense – Intangible Assets	$	1,184	$	1,133	$	1,099	$	1,099	$	1,099

Cash Flow Supplemental [Policy Text Block]

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2019		2018
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	4,338	$	10,451

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards Adopted

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 supersedes the requirements under ASC Topic

840

on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU

2016

-

02

are effective for fiscal years beginning after

December 15, 2018,

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

2016

-

02

to its consolidated financial statements effective

January 1, 2019.

See note

8

for further information on leases and the Company’s elections for applying the new standard.

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/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the 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. 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 adopted the updates in ASU

2018

-

02

effective

January 1, 2019,

applying them in the period of adoption and

not

retrospectively. On adoption, the Company reclassified

$784,000

of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates.

Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below.

(in thousands)	Unrealized Gains on Available-for- Sale Securities		Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits			AOCI/(L)
Balance on December 22, 2017 – Pre-tax	$	71	$	(5,672	)	$	(5,601	)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$	10	$	(794	)	$	(784	)

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.

The Company early adopted the amendments in ASU

2017

-

04

in the

first

quarter of

2019.

The Company had

no

indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had

no

impact on the Company’s consolidated financial statements.

XML

Note 1 - Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

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

March 31, 201 9 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,444
Corporate Debt Securities – Held by Captive Insurance Company			$	5,975
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,644
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		1,396
Total Assets	$	2,840	$	7,619

December 31, 201 8 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,294
Corporate Debt Securities – Held by Captive Insurance Company			$	5,898
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				1,586
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		838
Total Assets	$	2,132	$	7,484

Schedule of Inventory, Current [Table Text Block]

	March 31,		December 31,
(in thousands)	2019		2018
Finished Goods	$	35,771	$	37,130
Work in Process		20,503		20,393
Raw Material, Fuel and Supplies		50,458		48,747
Total Inventories	$	106,732	$	106,270

Schedule of Goodwill [Table Text Block]

(in thousands)	Gross Balance December 31, 2018		Accumulated Impairments		Balance (net of impairments) December 31, 2018		Adjustments to Goodwill in 2019		Balance (net of impairments) March 31, 2019
Manufacturing	$	18,270	$	--	$	18,270	$	--	$	18,270
Plastics		19,302		--		19,302		--		19,302
Total	$	37,572	$	--	$	37,572	$	--	$	37,572

Schedule of Finite-Lived Intangible Assets [Table Text Block]

March 31, 201 9 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,410	$	12,081	9	-	197
Other		154		81		73		17
Total	$	22,645	$	10,491	$	12,154

December 31, 201 8 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	10,127	$	12,364	12	-	200
Other		154		68		86		20
Total	$	22,645	$	10,195	$	12,450

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

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Amortization Expense – Intangible Assets	$	296	$	345

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

(in thousands)	2019		2020		2021		2022		2023
Estimated Amortization Expense – Intangible Assets	$	1,184	$	1,133	$	1,099	$	1,099	$	1,099

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

	As of March 31,
(in thousands)	2019		2018
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	4,338	$	10,451

Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]

(in thousands)	Unrealized Gains on Available-for- Sale Securities		Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits			AOCI/(L)
Balance on December 22, 2017 – Pre-tax	$	71	$	(5,672	)	$	(5,601	)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$	10	$	(794	)	$	(784	)

XML

Note 2 - Business Segment Information (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

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

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric Segment:
Retail Sales Revenue from Contracts with Customers	$	114,955		$	109,180
Changes in Accrued ARP Revenues		(1,049	)		(875	)
Total Retail Sales Revenue		113,906			108,305
Transmission Services Revenue		10,862			11,903
Wholesale Revenues – Company Generation		1,527			1,015
Other Revenues		1,814			1,742
Total Electric Segment Revenues		128,109			122,965
Manufacturing Segment:
Metal Parts and Tooling		66,724			56,927
Plastic Products and Tooling		9,045			10,235
Other		2,053			1,500
Total Manufacturing Segment Revenues		77,822			68,662
Plastics Segment – Sale of PVC Pipe Products		40,058			49,653
Intersegment Eliminations		(17	)		(14	)
Total	$	245,972		$	241,266

	Three Months Ended
	March 31,
(in thousands)	2019		2018
Electric	$	6,641	$	6,390
Manufacturing		584		554
Plastics		149		150
Corporate and Intersegment Eliminations		452		278
Total	$	7,826	$	7,372

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	4,771		$	2,098
Manufacturing		1,454			1,223
Plastics		1,329			2,414
Corporate		(1,926	)		(1,941	)
Total	$	5,628		$	3,794

	Three Months Ended
	March 31,
(in thousands)	2019			2018
Electric	$	18,700		$	16,668
Manufacturing		4,842			4,164
Plastics		3,729			6,844
Corporate		(947	)		(1,461	)
Total	$	26,324		$	26,215

	March 31,		December 31,
(in thousands)	2019		2018
Electric	$	1,737,278	$	1,728,534
Manufacturing		217,390		187,556
Plastics		104,544		91,630
Corporate		45,336		44,797
Total	$	2,104,548	$	2,052,517

XML

Note 3 - Rate and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

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
2018 Incentive and Cost Recovery	R – April 1, 2019	October 1, 2019	$	11,926		$0.00710/kwh
2017 Incentive and Cost Recovery	A – October 4, 2018	November 1, 2018	$	10,283		$0.00600/kwh
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 2017	$	9,868		$0.00536/kwh
Transmission Cost Recovery
2018 Annual Update–Scenario A	R – November 30, 2018	June 1, 2019	$	6,475		Various
–Scenario B			$	2,708		Various
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(3,311	)	Various
Environmental Cost Recovery
2018 Annual Update	A – November 29, 2018	December 1, 2018	$	--		0% of base
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of base
Renewable Resource Adjustment
2018 Annual Update	A – August 29, 2018	November 1, 2018	$	5,886		$.00244/kwh
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	1,279		$.00049/kwh
North Dakota
Renewable Resource Adjustment
2019 Annual Update	A – May 1, 2019	June 1, 2019	$	(235	)	-0.224% of base
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
Transmission Cost Recovery
2018 Supplemental Update	A – December 6, 2018	February 1, 2019	$	4,801		Various
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
Environmental Cost Recovery
2018 Update	A – December 19, 2018	February 1, 2019	$	(378	)	-0.310% of base
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
Generation Cost Recovery
2019 Initial Request	R – March 1, 2019	July 1, 2019	$	2,720		2.547% of base
South Dakota
Transmission Cost Recovery
2019 Annual Update	A – February 20, 2019	March 1, 2019	$	1,638		Various
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	1,171		Various
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
Environmental Cost Recovery
2018 Interim Rate Reset	A – October 18, 2018	October 18, 2018	$	(189	)	-$0.00075/kwh
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh

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

Rate Rider (in thousands)	2019			2018
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,152		$	2,516
Renewable Resource Recovery		1,316			525
Transmission Cost Recovery		641			(29	)
Environmental Cost Recovery		(1	)		(31	)
North Dakota
Transmission Cost Recovery		1,772			2,062
Renewable Resource Adjustment		729			1,967
Environmental Cost Recovery		575			1,821
Generation Cost Recovery		248			--
South Dakota
Transmission Cost Recovery		473			536
Conservation Improvement Program Costs and Incentives		244			229
Environmental Cost Recovery		(4	)		520
Total	$	8,145		$	10,116

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Note 4 - Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Schedule of Regulatory Assets and Liabilities [Table Text Block]

	March 31, 2019								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	$	6,355	$	116,835		$	123,190		see below
Accumulated ARO Accretion/Depreciation Adjustment 1		--		7,302			7,302		asset lives
Conservation Improvement Program Costs and Incentives 2		3,007		3,979			6,986			18
Deferred Marked-to-Market Losses 1		1,432		557			1,989			21
Minnesota Transmission Cost Recovery Rider Accrued Revenues 2		1,958		--			1,958			12
Deferred Income Taxes 1		--		1,557			1,557		asset lives
Big Stone II Unrecovered Project Costs – Minnesota 1		689		770			1,459			25
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		1,143			1,143		asset lives
Debt Reacquisition Premiums 1		203		701			904			162
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		416		--			416			12
Big Stone II Unrecovered Project Costs – South Dakota 1		117		292			409			42
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		180		130			310			33
South Dakota Deferred Rate Case Expenses Subject to Recovery 1		267		--			267			12
North Dakota Generation Cost Recovery Rider Accrued Revenues 2		248		--			248			12
Recoverable Fuel and Purchased Power Costs – South Dakota 1		197		--			197			12
Minnesota SPP Transmission Cost Recovery Tracker 1		--		117			117		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		52		--			52			4
Deferred Lease Expenses 1		--		44			44			48
Minnesota Environmental Cost Recovery Rider Accrued Revenues 2		38		--			38			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues 2		34		--			34			12
Total Regulatory Assets	$	15,193	$	133,427		$	148,620
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	141,452		$	141,452		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,555			83,555		asset lives
Refundable Fuel Clause Adjustment Revenues – Minnesota		5,149		--			5,149			12
North Dakota Renewable Resource Recovery Rider Accrued Refund		901		--			901			12
North Dakota Environmental Cost Recovery Rider Accrued Refund		669		--			669			12
Refundable Fuel Clause Adjustment Revenues – North Dakota		537		--			537			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		272		--			272			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		225			225		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			21
South Dakota Transmission Cost Recovery Rider Accrued Refund		151		--			151			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		103		--			103			12
Other		5		77			82			177
Total Regulatory Liabilities	$	7,787	$	225,496		$	233,283
Net Regulatory Asset/(Liability) Position	$	7,406	$	(92,069	)	$	(84,663	)

	December 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	$	6,346	$	118,433		$	124,779		see below
Accumulated ARO Accretion/Depreciation Adjustment 1		--		7,169			7,169		asset lives
Conservation Improvement Program Costs and Incentives 2		5,995		3,285			9,280			21
Deferred Marked-to-Market Losses 1		1,661		743			2,404			24
Minnesota Transmission Cost Recovery Rider Accrued Revenues 2		444		--			444			12
Deferred Income Taxes 1		--		2,423			2,423		asset lives
Big Stone II Unrecovered Project Costs – Minnesota 1		681		947			1,628			28
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1		--		986			986		asset lives
Debt Reacquisition Premiums 1		207		753			960			165
North Dakota Deferred Rate Case Expenses Subject to Recovery 1		455		--			455			12
Big Stone II Unrecovered Project Costs – South Dakota 1		100		342			442			53
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1		240		--			240			12
South Dakota Deferred Rate Case Expenses Subject to Recovery 1		178		--			178			12
Minnesota SPP Transmission Cost Recovery Tracker 1		--		176			176		see below
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1		328		--			328			4
Minnesota Environmental Cost Recovery Rider Accrued Revenues 2		121		--			121			12
Minnesota Renewable Resource Recovery Rider Accrued Revenues 2		452		--			452			12
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		17		--			17			12
Total Regulatory Assets	$	17,225	$	135,257		$	152,482
Regulatory Liabilities:
Deferred Income Taxes	$	--	$	142,779		$	142,779		asset lives
Accumulated Reserve for Estimated Removal Costs – Net of Salvage		--		83,229			83,229		asset lives
North Dakota Renewable Resource Recovery Rider Accrued Refund		177		--			177			12
North Dakota Transmission Cost Recovery Rider Accrued Refund		60		--			60			12
Revenue for Rate Case Expenses Subject to Refund – Minnesota		--		166			166		see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		187			187			24
South Dakota Transmission Cost Recovery Rider Accrued Refund		168		--			168			12
South Dakota Environmental Cost Recovery Rider Accrued Refund		207		--			207			12
Refundable Fuel Clause Adjustment Revenues		121		--			121			12
Other		5		108			113			180
Total Regulatory Liabilities	$	738	$	226,469		$	227,207
Net Regulatory Asset/(Liability) Position	$	16,487	$	(91,212	)	$	(74,725	)

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Note 5 - Common Shares and Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

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

Common Shares Outstanding, December 31, 2018	39,664,884
Issuances:
Executive Stock Performance Awards (2016 shares earned)	102,198
Vesting of Restricted Stock Units	17,850
Retirements:
Shares Withheld for Individual Income Tax Requirements	(55,224	)
Common Shares Outstanding, March 31, 2019	39,729,708

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

	2019		2018
Weighted Average Common Shares Outstanding – Basic		39,657,321		39,550,874
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		158,159		223,162
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		63,398		59,130
Nonvested Restricted Shares		21,922		27,643
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,365		2,873
Total Dilutive Shares		245,844		312,808
Weighted Average Common Shares Outstanding – Diluted		39,903,165		39,863,682

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Note 6 - Share-based Payments (Tables)

3 Months Ended

Mar. 31, 2019

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		15,600	$	49.6225	25% per year through February 6, 2023
Stock Performance Awards Granted:
Under Executive and Select Employee Agreements		47,800	$	42.875	December 31, 2021
Under Legacy Agreement		7,800	$	45.885	December 31, 2021

Share-based Payment Arrangement, Activity [Table Text Block]

	Three months ended
	March 31,
(in thousands)	2019		2018
Stock Performance Awards Granted to Executive Officers	$	1,113	$	651
Restricted Stock Units Granted to Executive Officers		427		249
Restricted Stock Granted to Executive Officers		--		16
Restricted Stock Granted to Directors		165		166
Restricted Stock Units Granted to Non-Executive Employees		91		64
Totals	$	1,796	$	1, 146

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Note 8 - Leases (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Leases, Right-of-use Assets and Lease Liabilities By Business Segment [Table Text Block]

(in thousands)	Electric			Manufacturing			Plastics			Corporate			Total
Right of Use Assets – Operating Leases:
Gross	$	3,421		$	16,976		$	666		$	767		$	21,830
Accumulated Amortization		(257	)		(734	)		(97	)		(30	)		(1,118	)
Net of Accumulated Amortization	$	3,164		$	16,242		$	569		$	737		$	20,712
Obligations:
Current Operating Lease Liabilities	$	913		$	2,458		$	379		$	150		$	3,900
Long-Term Operating Lease Liabilities		2,470			13,852			190			648			17,160
Total Lease Liabilities	$	3,383		$	16,310		$	569		$	798		$	21,060

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

	Right-of-Use Operating Leases
(in thousands)	OTP			Nonelectric			Total
2019	$	845		$	3,078		$	3,923
2020		1,115			3,948			5,063
2021		1,091			3,657			4,748
2022		207			3,529			3,736
2023		196			3,209			3,405
Beyond 2023		447			8,023			8,470
Total Minimum Obligations	$	3,901		$	25,443		$	29,344
Interest Component of Obligations		(355	)		(4,376	)		(4,731	)
Present Value of Leases Commencing after March 31, 2019		(163	)		(3,390	)		(3,553	)
Present Value of Minimum Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

Lessee, Operating Lease, Lease Obligation Activity [Table Text Block]

(in thousands)	OTP			Nonelectric			Total
Operating Lease Obligations, January 1, 2019	$	3,609		$	16,760		$	20,369
Non-cash Acquisition of Right-of-Use Assets		--			1,725			1,725
Lease Obligation Payments		(270	)		(1,020	)		(1,290	)
Interest Component of Lease Obligation Payment		44			212			256
Operating Lease Obligations, March 31, 2019	$	3,383		$	17,677		$	21,060

Lease, Cost [Table Text Block]

(in thousands)	Operating Lease Cost		Variable Lease Cost		Total Lease Cost
Plant in Service or CWIP	$	9	$	--	$	9
Inventory		225		--		225
Cost of Products Sold		1,036		27		1,063
Electric Operation and Maintenance Expenses		66		--		66
Other Nonelectric Expenses		54		--		54
Total	$	1,390	$	27	$	1,417

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Note 10 - Short-term and Long-term Borrowings (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Schedule of Line of Credit Facilities [Table Text Block]

(in thousands)	Line Limit		In Use on March 31, 2019		Restricted due to Outstanding Letters of Credit		Available on March 31, 2019		Available on December 31, 2018
Otter Tail Corporation Credit Agreement	$	130,000	$	27,742	$	--	$	102,258	$	120,785
OTP Credit Agreement		170,000		15,859		300		153,841		160,316
Total	$	300,000	$	43,601	$	300	$	256,099	$	281,101

Schedule of Debt [Table Text Block]

March 31, 201 9 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	15,859	$	27,742	$	43,601
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
PACE Note, 2.54%, due March 18, 2021				480		480
Total	$	512,000	$	80,480	$	592,480
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		174		174
Unamortized Long-Term Debt Issuance Costs		1,890		394		2,284
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,110	$	79,912	$	590,022
Total Short-Term and Long-Term Debt (with current maturities)	$	525,969	$	107,828	$	633,797

December 31, 2018 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	9,384	$	9,215	$	18,599
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
PACE Note, 2.54%, due March 18, 2021				523		523
Total	$	512,000	$	80,523	$	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		172		172
Unamortized Long-Term Debt Issuance Costs		1,942		407		2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	510,058	$	79,944	$	590,002
Total Short-Term and Long-Term Debt (with current maturities)	$	519,442	$	89,331	$	608,773

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Note 11 - Pension Plan and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Schedule of Net Benefit Costs [Table Text Block]

	Three Months Ended March 31,
(in thousands)	2019			2018
Service Cost—Benefit Earned During the Period	$	1,373		$	1,615
Interest Cost on Projected Benefit Obligation		3,603			3,363
Expected Return on Assets		(5,325	)		(5,300	)
Amortization of Prior-Service Cost:
From Regulatory Asset		1			4
From Other Comprehensive Income 1		2			--
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,163			1,784
From Other Comprehensive Income 1		27			44
Net Periodic Pension Cost 2	$	844		$	1,510
1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits .
2 Allocation of Costs:
Service c osts included in OTP c apital e xpenditures	$	390		$	328
Service c osts included in e lectric o peration and m aintenance e xpenses		950			1,247
Service c osts included in o ther n onelectric e xpenses		33			40
Nonservice costs capitalized as regulatory assets		(150	)		(21	)
Nonservice costs included in n onservice cost components of postretirement benefits		(379	)		(84	)

	Three Months Ended March 31,
(in thousands)	2019		2018
Service Cost—Benefit Earned During the Period	$	105	$	100
Interest Cost on Projected Benefit Obligation		434		399
Amortization of Prior Service Cost:
From Regulatory Asset		1		4
From Other Comprehensive Income 1		4		10
Amortization of Net Actuarial Loss:
From Regulatory Asset		31		67
From Other Comprehensive Income 1		87		165
Net Periodic Pension Cost 2	$	662	$	745
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 cost components of postretirement benefits .
2 Allocation of Costs:
Service c osts included in e lectric o peration and m aintenance e xpenses	$	26	$	25
Service costs included in ot her n onelectric e xpenses		79		75
Nonservice c osts included in n onservice cost components of postretirement benefits		557		645

	Three Months Ended March 31,
(in thousands)	2019			2018
Service Cost—Benefit Earned During the Period	$	321		$	382
Interest Cost on Projected Benefit Obligation		770			645
Amortization of Net Actuarial Loss:
From Regulatory Asset		393			412
From Other Comprehensive Income 1		10			10
Net Periodic Postretirement Benefit Cost 2	$	1,494		$	1,449
Effect of Medicare Part D Subsidy	$	(45	)	$	(37	)
1 Corporate cost included in nonservice cost components of postretirement benefits.
2 Allocation of Costs:
Service c osts included in OTP capital expenditures	$	91		$	78
Service costs included in electric operation and maintenance expenses		223			294
Service costs included in other nonelectric expenses		7			10
Nonservice costs capitalized as regulatory assets		333			217
Nonservice costs included in n onservice cost components of postretirement benefits		840			850

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Note 12 - Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Fair Value, by Balance Sheet Grouping [Table Text Block]

	March 31, 2019						December 31, 2018
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents	$	891		$	891		$	861		$	861
Short-Term Debt		(43,601	)		(43,601	)		(18,599	)		(18,599	)
Long-Term Debt including Current Maturities		(590,196	)		(611,219	)		(590,174	)		(601,513	)

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Note 14 - Income Tax Expense - Continuing Operations (Tables)

3 Months Ended

Mar. 31, 2019

Notes Tables

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Three Months Ended March 31,
(in thousands)	2019			2018
Income Before Income Taxes	$	31,952		$	30,009
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)		8,308			7,802
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates		(983	)		(1,073	)
Excess Tax Deduction – Equity Method Stock Awards		(827	)		(624	)
Corporate Owned Life Insurance		(409	)		(8	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(258	)		(258	)
Research and Development and Other Tax Credits		(188	)		(180	)
Allowance for Funds Used During Construction – Equity		(86	)		(167	)
Federal Production Tax Credits (PTCs)		--			(1,120	)
Other Comprehensive Income Deferred Tax Rate Adjustment		--			(531	)
Other Items – Net		71			(47	)
Income Tax Expense	$	5,628		$	3,794
Effective Income Tax Rate		17.6	%		12.6	%

Summary of Income Tax Contingencies [Table Text Block]

(in thousands)	2019		2018
Balance on January 1	$	1,282	$	684
Increases Related to Tax Positions for Current Year		38		36
Uncertain Positions Resolved During Year		--		(44	)
Balance on March 31	$	1,320	$	676

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Note 1 - Summary of Significant Accounting Policies (Details Textual) - USD ($)		3 Months Ended
	Jan. 01, 2019	Mar. 31, 2019	Mar. 31, 2018
Goodwill, Impairment Loss			$ 0
Goodwill, Period Increase (Decrease), Total		$ 0
Accounting Standards Update 2018-02 [Member]
Tax Cuts and Jobs Act, Reclassification of Stranded Tax Effect From AOCI to Retained Earnings	$ 784,000
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		$ 53,100,000
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage		35.00%

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Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 1 [Member]
Assets:
Total Assets	$ 2,840	$ 2,132
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets:
Investments	1,444	1,294
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	1,396	838
Fair Value, Inputs, Level 2 [Member]
Assets:
Total Assets	7,619	7,484
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets:
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Assets:
Investments	5,975	5,898
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments	1,644	$ 1,586
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, 2019	Dec. 31, 2018
Finished Goods	$ 35,771	$ 37,130
Work in Process	20,503	20,393
Raw Material, Fuel and Supplies	50,458	48,747
Total Inventories	$ 106,732	$ 106,270

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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, 2019	Dec. 31, 2018
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, 2019	Dec. 31, 2018
Gross Carrying Amount	$ 22,645	$ 22,645
Accumulated Amortization	10,491	10,195
Net Carrying Amount	12,154	12,450
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	10,410	10,127
Net Carrying Amount	$ 12,081	$ 12,364
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	270 days	1 year
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	16 years 150 days	16 years 240 days
Other Intangible Assets [Member]
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	81	68
Net Carrying Amount	$ 73	$ 86
Remaining Amortization Periods (Month)	1 year 150 days	1 year 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, 2019	Mar. 31, 2018
Amortization Expense – Intangible Assets	$ 296	$ 345

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Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Mar. 31, 2019 USD ($)
2019	$ 1,184
2020	1,133
2021	1,099
2022	1,099
2023	$ 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, 2019	Mar. 31, 2018
Transactions Related to Capital Additions not Settled in Cash	$ 4,338	$ 10,451

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Note 1 - Summary of Significant Accounting Policies - Effect of Stranded Tax Effect (Details) - USD ($)			3 Months Ended
	Jan. 01, 2019	Dec. 22, 2017	Mar. 31, 2019	Mar. 31, 2018
Other Comprehensive Income (Loss)			$ 168,000	$ (502,000)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts
AOCI, Accumulated Gain (Loss), Debt Securities, Available-for-sale, Parent [Member]
Other Comprehensive Income (Loss)		$ 71
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$ 10
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member]
Other Comprehensive Income (Loss)		(5,672)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	(794)
AOCI Attributable to Parent [Member]
Other Comprehensive Income (Loss)		$ (5,601)	168,000	$ (502,000)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$ (784)		$ (784,000)

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Note 2 - Business Segment Information (Details Textual)	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Number of Reportable Segments	3
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member]
Number of Customers			0
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Electric [Member]
Number of Customers			1
Concentration Risk, Percentage			11.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member]
Number of Customers			5
Concentration Risk, Percentage			52.00%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member]
Number of Customers			1
Concentration Risk, Percentage			22.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member]
Number of Customers			1
Concentration Risk, Percentage			11.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member]
Number of Customers			2
Concentration Risk, Percentage			39.10%
Revenue Benchmark [Member] | UNITED STATES
Concentration Risk, Percentage	99.00%	98.30%

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Note 2 - Business Segment Information - Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Total Operating Revenues	$ 245,972	$ 241,266
Interest charges	7,826	7,372
Income Tax Expense	5,628	3,794
Net Income (Loss)	26,324	26,215
Assets	2,104,548		$ 2,052,517
Operating Segments [Member] | Electric [Member]
Regulated operating revenues	128,109	122,965
Interest charges	6,641	6,390
Income Tax Expense	4,771	2,098
Net Income (Loss)	18,700	16,668
Assets	1,737,278		1,728,534
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	114,955	109,180
Changes in Accrued ARP Revenues	(1,049)	(875)
Regulated operating revenues	113,906	108,305
Operating Segments [Member] | Electric [Member] | Electric Transmission [Member]
Revenue from Contracts with Customers	10,862	11,903
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	1,527	1,015
Operating Segments [Member] | Electric [Member] | Product and Service, Other [Member]
Revenue from Contracts with Customers	1,814	1,742
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	77,822	68,662
Interest charges	584	554
Income Tax Expense	1,454	1,223
Net Income (Loss)	4,842	4,164
Assets	217,390		187,556
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	66,724	56,927
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	9,045	10,235
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	2,053	1,500
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	40,058	49,653
Interest charges	149	150
Income Tax Expense	1,329	2,414
Net Income (Loss)	3,729	6,844
Assets	104,544		91,630
Corporate and Eliminations [Member]
Interest charges	452	278
Income Tax Expense	(1,926)	(1,941)
Net Income (Loss)	(947)	(1,461)
Assets	45,336		$ 44,797
Intersegment Eliminations [Member]
Regulated operating revenues	$ (17)	$ (14)

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Note 3 - Rate and Regulatory Matters (Details Textual)															1 Months Ended		3 Months Ended	12 Months Ended
	Apr. 01, 2019 USD ($)	Dec. 01, 2018	Oct. 16, 2018	Sep. 26, 2018 USD ($)	Apr. 20, 2018 USD ($)	Mar. 23, 2018 USD ($)	Mar. 22, 2018 USD ($)	Nov. 16, 2016 USD ($)	Sep. 28, 2016	May 25, 2016	Feb. 12, 2015	Nov. 06, 2014	Nov. 12, 2013	Jun. 01, 2011 USD ($)	Jun. 30, 2016	Dec. 22, 2015	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017	Mar. 01, 2018 USD ($)	Dec. 20, 2017 USD ($)	Nov. 02, 2017 USD ($)	May 01, 2017	Dec. 31, 2016 USD ($)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent																		21.00%	35.00%
Regulatory Liabilities, Total																	$ 233,283,000	$ 227,207,000
MONTANA
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	10,400,000
NORTH DAKOTA
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	800,000
Federal Energy Regulatory Commission [Member]
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	300,000
Otter Tail Power Company [Member] | Litigation Case with Minnesota Customers [Member]
Loss Contingency, Estimate of Possible Loss																	2,500,000
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			10.41%						10.82%
Regulatory Liabilities, Total																		$ 1,600,000						$ 2,700,000
Contract with Customer, Refund Liability, Total																	1,600,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | Maximum [Member]
Proposed Reduced Return on Equity Used in Transmission Rates			13.08%
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																							8.61%
Percentage of Allowed Rate of Return on Equity																							10.74%
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%
Expected Rate of Financial Incentive Reduction										50.00%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member]
Financial Incentives Recognized During Period	$ 3,000,000
Otter Tail Power Company [Member] | MONTANA
Environmental Cost Recovery Rider Rate		0.00%
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%
Percentage of Allowed Rate of Return on Equity																						10.30%
General Rate Revenue Increase Requested																					$ 12,800,000	$ 13,100,000
Percentage of Increase in Base Rate Revenue Requested																						8.72%
Public Utilities, Interim Rate Requirement, Decrease in Amount																				$ 4,500,000
Public Utilities, Interim Rate Requirement, Amount																				$ 8,300,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member]
Percentage of Allowed Rate of Return on Equity						10.30%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 4,600,000		$ 7,100,000	$ 13,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage				3.10%		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
Percentage of Requested Allowed Rate of Return on Equity				9.77%
Equity to Total Capitalization Ratio Basis for Return on Equity				52.50%
Revenue Collected Under Interim Rates Subject to Refund																	3,400,000
Excess Revenue Collected for Income Taxes																	800,000
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2018 General Rate Case [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%
Contract with Customer, Liability, Revenue Recognized																	1,000,000
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] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member]
Current Project Cost																	$ 106,000,000
Expanded Capacity of Projects																	345
Extended Distance of Transmission Line																	163
Percentage of Assets of Project																	100.00%
Otter Tail Power Company [Member] | Astoria Station Project [Member]
Expanded Capacity of Projects (MW)																	245
Current Project Capitalized Cost																	$ 7,700,000
Otter Tail Power Company [Member] | Merricourt Project [Member] | EDF [Member]
Expanded Capacity of Projects (MW)								150
Asset Purchase Agreement, Purchase Price								$ 34,700,000
Turnkey Engineering, Procurement and Construction Services Agreement, Costs								$ 200,500,000
Current Project Cost																	$ 5,300,000

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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, 2019 USD ($) kWh Boe	Mar. 31, 2018 USD ($)
Annual Revenue		$ 8,145	$ 10,116
Annual Revenue		8,145	10,116
MONTANA | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	[1]	2,152	2,516
Annual Revenue	[1]	$ 2,152	2,516
MONTANA | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member]
R - Request Date		Apr. 01, 2019
Effective Date Requested or Approved		Oct. 01, 2019
Annual Revenue		$ 11,926
Rate rider rate (Kilowatt-Hour) | kWh		0.0071
Annual Revenue		$ 11,926
MONTANA | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved		Nov. 01, 2018
Annual Revenue		$ 10,283
Rate rider rate (Kilowatt-Hour) | kWh		0.006
A - Approval Date		Oct. 04, 2018
Annual Revenue		$ 10,283
MONTANA | 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
Annual Revenue		$ 9,868
MONTANA | Transmission Cost Recovery Rider [Member]
Annual Revenue		641	(29)
Annual Revenue		$ 641	(29)
MONTANA | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member]
R - Request Date		Nov. 30, 2018
Effective Date Requested or Approved		Jun. 01, 2019
Annual Revenue		$ 6,475
Rate		Various
Annual Revenue		$ 6,475
MONTANA | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario B [Member]
Annual Revenue		$ 2,708
Rate		Various
Annual Revenue		$ 2,708
MONTANA | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Nov. 01, 2017
Annual Revenue		$ (3,311)
A - Approval Date		Oct. 30, 2017
Rate		Various
Annual Revenue		$ (3,311)
MONTANA | Environmental Cost Recovery Rider [Member]
Annual Revenue		(1)	(31)
Annual Revenue		$ (1)	(31)
MONTANA | 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%)
Annual Revenue		$ (1,943)
MONTANA | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Dec. 01, 2018
Annual Revenue
A - Approval Date		Nov. 29, 2018
Rate of base		0.00%
Annual Revenue
MONTANA | Renewable Resource Adjustment [Member]
Annual Revenue		1,316	525
Annual Revenue		$ 1,316	525
MONTANA | 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
Annual Revenue		$ 1,279
MONTANA | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Nov. 01, 2018
Annual Revenue		$ 5,886
Rate rider rate (Kilowatt-Hour) | Boe		0.00244
A - Approval Date		Aug. 29, 2018
Annual Revenue		$ 5,886
NORTH DAKOTA | Transmission Cost Recovery Rider [Member]
Annual Revenue		1,772	2,062
Annual Revenue		$ 1,772	2,062
NORTH DAKOTA | 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
Annual Revenue		$ 7,469
NORTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member]
Effective Date Requested or Approved		Feb. 01, 2019
Annual Revenue		$ 4,801
A - Approval Date		Dec. 06, 2018
Rate		Various
Annual Revenue		$ 4,801
NORTH DAKOTA | 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
Annual Revenue		$ 7,959
NORTH DAKOTA | Environmental Cost Recovery Rider [Member]
Annual Revenue		575	1,821
Annual Revenue		$ 575	1,821
NORTH DAKOTA | 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%
Annual Revenue		$ 8,537
NORTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Feb. 01, 2019
Annual Revenue		$ (378)
A - Approval Date		Dec. 19, 2018
Rate of base		(0.31%)
Annual Revenue		$ (378)
NORTH DAKOTA | 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%
Annual Revenue		$ 7,718
NORTH DAKOTA | Renewable Resource Adjustment [Member]
Annual Revenue		729	1,967
Annual Revenue		$ 729	1,967
NORTH DAKOTA | 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%
Annual Revenue		$ 9,989
NORTH DAKOTA | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved		Jun. 01, 2019
Annual Revenue		$ (235)
A - Approval Date		May 01, 2019
Rate of base		(0.224%)
Annual Revenue		$ (235)
NORTH DAKOTA | 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%
Annual Revenue		$ 9,650
NORTH DAKOTA | Generation Cost Recovery [Member]
Annual Revenue		248
Annual Revenue		$ 248
NORTH DAKOTA | Generation Cost Recovery [Member] | The 2019 Initial Request [Member]
R - Request Date		Mar. 01, 2019
Effective Date Requested or Approved		Jul. 01, 2019
Annual Revenue		$ 2,720
Rate of base		2.547%
Annual Revenue		$ 2,720
SOUTH DAKOTA | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue		244	229
Annual Revenue		244	229
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member]
Annual Revenue		473	536
Annual Revenue		$ 473	536
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved		Mar. 01, 2019
Annual Revenue		$ 1,638
A - Approval Date		Feb. 20, 2019
Rate		Various
Annual Revenue		$ 1,638
SOUTH DAKOTA | 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
Annual Revenue		$ 1,779
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved		Oct. 18, 2018
Annual Revenue		$ 1,171
A - Approval Date		Oct. 18, 2018
Rate		Various
Annual Revenue		$ 1,171
SOUTH DAKOTA | 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
Annual Revenue		$ 2,053
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member]
Annual Revenue		(4)	520
Annual Revenue		$ (4)	$ 520
SOUTH DAKOTA | 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) | Boe		0.00483
A - Approval Date		Oct. 13, 2017
Annual Revenue		$ 2,082
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved		Oct. 18, 2018
Annual Revenue		$ (189)
Rate rider rate (Kilowatt-Hour) | kWh		(0.00075)
A - Approval Date		Oct. 18, 2018
Annual Revenue		$ (189)

[1] Includes MNCIP costs recovered in base rates.

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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, 2019	Mar. 31, 2018
Revenues recorded under rate riders		$ 8,145	$ 10,116
MONTANA | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	[1]	2,152	2,516
MONTANA | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		1,316	525
MONTANA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		641	(29)
MONTANA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		(1)	(31)
NORTH DAKOTA | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		729	1,967
NORTH DAKOTA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,772	2,062
NORTH DAKOTA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		575	1,821
NORTH DAKOTA | Generation Cost Recovery [Member]
Revenues recorded under rate riders		248
SOUTH DAKOTA | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders		244	229
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		473	536
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		$ (4)	$ 520

[1] Includes MNCIP costs recovered in base rates.

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Note 4 - Regulatory Assets and Liabilities (Details Textual)	3 Months Ended
	Mar. 31, 2019
Regulatory Noncurrent Asset, Remaining Recovery Period	13 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, 2019	Dec. 31, 2018
Regulatory Assets - Current		$ 15,193	$ 17,225
Regulatory Assets - Long -Term		133,427	135,257
Regulatory Assets - Total		$ 148,620	$ 152,482
Regulatory Assets - Remaining Recovery/Refund Period (Month)
Regulatory Liabilities - Current		$ 7,787	$ 738
Regulatory Liabilities - Long -Term		225,496	226,469
Regulatory Liabilities, Total		$ 233,283	$ 227,207
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)
Net Regulatory Asset Position - Current		$ 7,406	$ 16,487
Net Regulatory Asset Position - Long-Term		(92,069)	(91,212)
Net Regulatory Asset/(Liability) Position		(84,663)	(74,725)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		141,452	142,779
Regulatory Liabilities, Total		$ 141,452	$ 142,779
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		83,555	83,229
Regulatory Liabilities, Total		$ 83,555	$ 83,229
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 901	$ 177
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 901	$ 177
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 272	$ 60
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 272	$ 60
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues - Minnesota [Member]
Regulatory Liabilities - Current		$ 5,149
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 5,149
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		225	166
Regulatory Liabilities, Total		$ 225	$ 166
Regulatory Liabilities - Remaining Recovery/Refund Period		see below	see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		187	187
Regulatory Liabilities, Total		$ 187	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 270 days	2 years
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 669
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 669
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 151	$ 168
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 151	$ 168
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues – North Dakota [Member]
Regulatory Liabilities - Current		$ 537
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 537
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 103	$ 207
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 103	$ 207
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current			$ 121
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total			$ 121
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year
Other [Member]
Regulatory Liabilities - Current		$ 5	$ 5
Regulatory Liabilities - Long -Term		77	108
Regulatory Liabilities, Total		$ 82	$ 113
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		14 years 270 days	15 years
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 6,355	$ 6,346
Regulatory Assets - Long -Term	[1]	116,835	118,433
Regulatory Assets - Total	[1]	$ 123,190	$ 124,779
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	7,302	7,169
Regulatory Assets - Total	[1]	$ 7,302	$ 7,169
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 3,007	$ 5,995
Regulatory Assets - Long -Term	[2]	3,979	3,285
Regulatory Assets - Total	[2]	$ 6,986	$ 9,280
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year 180 days	1 year 270 days
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 1,432	$ 1,661
Regulatory Assets - Long -Term	[1]	557	743
Regulatory Assets - Total	[1]	$ 1,989	$ 2,404
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year 270 days	2 years
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 1,958	$ 444
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 1,958	$ 444
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Deferred Income Taxes [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	1,557	2,423
Regulatory Assets - Total	[1]	$ 1,557	$ 2,423
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 689	$ 681
Regulatory Assets - Long -Term	[1]	770	947
Regulatory Assets - Total	[1]	$ 1,459	$ 1,628
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 30 days	2 years 120 days
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]	1,143	986
Regulatory Assets - Total	[1]	$ 1,143	$ 986
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 203	$ 207
Regulatory Assets - Long -Term	[1]	701	753
Regulatory Assets - Total	[1]	$ 904	$ 960
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	13 years 180 days	13 years 270 days
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 416	$ 455
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 416	$ 455
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 117	$ 100
Regulatory Assets - Long -Term	[1]	292	342
Regulatory Assets - Total	[1]	$ 409	$ 442
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	3 years 180 days	4 years 150 days
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]	$ 180	$ 240
Regulatory Assets - Long -Term	[1]	130
Regulatory Assets - Total	[1]	$ 310	$ 240
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 270 days	1 year
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 267	$ 178
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 267	$ 178
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
North Dakota Generation Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 248
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 248
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year
Minnesota SPP Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	117	176
Regulatory Assets - Total	[1]	$ 117	$ 176
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Recoverable Fuel and Purchased Power Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 197
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 197
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]	$ 52	$ 328
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 52	$ 328
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	120 days	120 days
Minnesota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 38	$ 121
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 38	$ 121
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 34	$ 452
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 34	$ 452
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Deferred Lease Expenses [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	44
Regulatory Assets - Total	[1]	$ 44
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	4 years
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 17
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 17
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year

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

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

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Note 5 - Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	3 Months Ended
	Mar. 31, 2019 shares
Common Shares Outstanding, beginning balance (in shares)	39,664,884
Issuances:
Vesting of Restricted Stock Units (in shares)	17,850
Retirements:
Shares Withheld for Individual Income Tax Requirements (in shares)	(55,224)
Common Shares Outstanding, ending balance (in shares)	39,729,708
Performance Awards 2016 [Member]
Issuances:
Executive Stock Performance Awards (2016 shares earned) (in shares)	102,198

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Note 5 - Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Weighted Average Common Shares Outstanding – Basic (in shares)	39,657,321	39,550,874
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)	158,159	223,162
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	63,398	59,130
Nonvested Restricted Shares (in shares)	21,922	27,643
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,365	2,873
Total Dilutive Shares (in shares)	245,844	312,808
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,903,165	39,863,682

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Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions		3 Months Ended
	Feb. 05, 2018	Mar. 31, 2019
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total		$ 6.2
Share-based Payment Arrangement, Nonvested Award, 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	55,600
Period Specified for Average Adjusted Return	3 years
Number of Trading Days	20 days
Number of Shares Authorized for Actual Payment	83,400
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 Payment Arrangement, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800

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Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details)	Feb. 13, 2019 $ / shares shares
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member]
Shares/units granted (in shares) | shares	15,600
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 49.6225
Shares/units granted, vesting date	Feb. 06, 2023
Performance Shares [Member] | The 2014 Stock Incentive Plan [Member]
Shares/units granted (in shares) | shares	47,800
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 42.875
Shares/units granted, vesting date	Dec. 31, 2021
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member]
Shares/units granted (in shares) | shares	7,800
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 45.885
Shares/units granted, vesting date	Dec. 31, 2021

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Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals)	Feb. 13, 2019
The 2014 Stock Incentive Plan [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, 2019	Mar. 31, 2018
Stock compensation expense	$ 1,796	$ 1,146
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	1,113	651
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	427	249
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense		16
Restricted Stock [Member] | Director [Member]
Stock compensation expense	165	166
Restricted Stock [Member] | Non-executive Employees [Member]
Stock compensation expense	$ 91	$ 64

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Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Capitalization, Long-term Debt and Equity, Total	$ 1,330,521	$ 1,318,865
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio	53.20%
Net Assets Restricted from Distribution	$ 484,000
Capitalization, Long-term Debt and Equity, Total	$ 1,200,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Minimum [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	47.90%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	58.50%

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Note 8 - Leases (Details Textual) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating Lease, Right-of-Use Asset	$ 20,712
Operating Lease, Weighted Average Remaining Lease Term	6 years
Operating Lease, Weighted Average Discount Rate, Percent	5.00%
Operating Lease, Liability, Total	$ 21,060		$ 20,369
Lease of Warehouse by T.O. Plastics [Member]
Lessee, Operating Lease, Term of Contract	10 years
Lease for 20 Coal Rail Cars [Member]
Lessee, Operating Lease, Term of Contract	2 years 90 days
Minimum [Member]
Lessee, Operating Lease, Term of Contract	1 year
Maximum [Member]
Lessee, Operating Lease, Term of Contract	10 years
Accounting Standards Update 2016-02 [Member]
Operating Lease, Right-of-Use Asset		$ 20,000
Operating Lease, Liability, Total		$ 20,000

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Note 8 - Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Gross	$ 21,830
Accumulated Amortization	(1,118)
Net of Accumulated Amortization	20,712
Current Operating Lease Liabilities	3,900
Long-Term Operating Lease Liabilities	17,160
Total Lease Liabilities	21,060	$ 20,369
Electric [Member]
Gross	3,421
Accumulated Amortization	(257)
Net of Accumulated Amortization	3,164
Current Operating Lease Liabilities	913
Long-Term Operating Lease Liabilities	2,470
Total Lease Liabilities	3,383
Manufacturing [Member]
Gross	16,976
Accumulated Amortization	(734)
Net of Accumulated Amortization	16,242
Current Operating Lease Liabilities	2,458
Long-Term Operating Lease Liabilities	13,852
Total Lease Liabilities	16,310
Plastics [Member]
Gross	666
Accumulated Amortization	(97)
Net of Accumulated Amortization	569
Current Operating Lease Liabilities	379
Long-Term Operating Lease Liabilities	190
Total Lease Liabilities	569
Corporate Segment [Member]
Gross	767
Accumulated Amortization	(30)
Net of Accumulated Amortization	737
Current Operating Lease Liabilities	150
Long-Term Operating Lease Liabilities	648
Total Lease Liabilities	$ 798

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Note 8 - Leases - Lease Obligations (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
2019	$ 3,923
2020	5,063
2021	4,748
2022	3,736
2023	3,405
Beyond 2023	8,470
Total Minimum Obligations	29,344
Interest Component of Obligations	(4,731)
Present Value of Leases Commencing after March 31, 2019	(3,553)
Present Value of Minimum Obligations, March 31, 2019	21,060	$ 20,369
OTP [Member]
2019	845
2020	1,115
2021	1,091
2022	207
2023	196
Beyond 2023	447
Total Minimum Obligations	3,901
Interest Component of Obligations	(355)
Present Value of Leases Commencing after March 31, 2019	(163)
Present Value of Minimum Obligations, March 31, 2019	3,383	3,609
Nonelectric Companies [Member]
2019	3,078
2020	3,948
2021	3,657
2022	3,529
2023	3,209
Beyond 2023	8,023
Total Minimum Obligations	25,443
Interest Component of Obligations	(4,376)
Present Value of Leases Commencing after March 31, 2019	(3,390)
Present Value of Minimum Obligations, March 31, 2019	$ 17,677	$ 16,760

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Note 8 - Leases - Operating Lease Obligation (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019 USD ($)
Operating Lease Obligations, beginning balance	$ 20,369
Non-cash Acquisition of Right-of-Use Assets	1,725
Lease Obligation Payments	(1,290)
Interest Component of Lease Obligation Payment	256
Operating Lease Obligations, ending balance	21,060
OTP [Member]
Operating Lease Obligations, beginning balance	3,609
Non-cash Acquisition of Right-of-Use Assets
Lease Obligation Payments	(270)
Interest Component of Lease Obligation Payment	44
Operating Lease Obligations, ending balance	3,383
Nonelectric Companies [Member]
Operating Lease Obligations, beginning balance	16,760
Non-cash Acquisition of Right-of-Use Assets	1,725
Lease Obligation Payments	(1,020)
Interest Component of Lease Obligation Payment	212
Operating Lease Obligations, ending balance	$ 17,677

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Note 8 - Leases - Allocation of Lease Costs (Details)	3 Months Ended
	Mar. 31, 2019 USD ($)
Operating lease cost	$ 1,390
Variable lease cost	27
Total lease cost	1,417
Production Fuel [Member]
Operating lease cost	9
Variable lease cost
Total lease cost	9
Purchase Power [Member]
Operating lease cost	225
Variable lease cost
Total lease cost	225
Cost of Sales [Member]
Operating lease cost	1,036
Variable lease cost	27
Total lease cost	1,063
Electric Operating and Maintenance Expenses [Member]
Operating lease cost	66
Variable lease cost
Total lease cost	66
Other Nonelectric Expenses [member]
Operating lease cost	54
Variable lease cost
Total lease cost	$ 54

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Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1.6
Otter Tail Power Company [Member] | Construction Programs [Member]
Long-term Purchase Commitment, Amount	$ 70.5	$ 64.5
Contract Expiration Year	2021
Otter Tail Power Company [Member] | Capacity and Energy Requirements [Member]
Contract Expiration Year	2042
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2040
Otter Tail Power Company [Member] | Coal Purchase Commitments 3 [Member]
Contract Expiration Year	2020
Otter Tail Power Company [Member] | OTP Land Easements [Member]
Long-term Purchase Commitment, Amount	$ 10.8
Contract Expiration Year	2034
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount	$ 4.7	$ 5.0

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Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Line Limit	$ 300,000
In Use	43,601
Restricted due to Outstanding Letters of Credit	300
Available	256,099	$ 281,101
Otter Tail Corporation Credit Agreement [Member]
Line Limit	130,000
In Use	27,742
Restricted due to Outstanding Letters of Credit
Available	102,258	120,785
OTP Credit Agreement [Member]
Line Limit	170,000
In Use	15,859
Restricted due to Outstanding Letters of Credit	300
Available	$ 153,841	$ 160,316

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Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Short-Term Debt	$ 43,601	$ 18,599
Long-Term Debt	592,480	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	174	172
Unamortized Long-Term Debt Issuance Costs	2,284	2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	590,022	590,002
Total Short-Term and Long-Term Debt (with current maturities)	633,797	608,773
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	100,000
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	480	523
Otter Tail Power Company [Member]
Short-Term Debt	15,859	9,384
Long-Term Debt	512,000	512,000
Less: Current Maturities net of Unamortized Debt Issuance Costs
Unamortized Long-Term Debt Issuance Costs	1,890	1,942
Total Long-Term Debt net of Unamortized Debt Issuance Costs	510,110	510,058
Total Short-Term and Long-Term Debt (with current maturities)	525,969	519,442
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	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	27,742	9,215
Long-Term Debt	80,480	80,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	174	172
Unamortized Long-Term Debt Issuance Costs	394	407
Total Long-Term Debt net of Unamortized Debt Issuance Costs	79,912	79,944
Total Short-Term and Long-Term Debt (with current maturities)	107,828	89,331
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] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 480	$ 523

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Note 10 - 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, 2019	Dec. 31, 2018
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt, Interest Rate	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt, Interest Rate	4.07%	4.07%
Long-Term Debt, Due Date	Feb. 07, 2048	Feb. 07, 2048
Long-Term Debt, Due Date	Feb. 07, 2048	Feb. 07, 2048
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

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Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual) $ in Millions	1 Months Ended
	Jan. 31, 2019 USD ($)
Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 10

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Note 11 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,373	$ 1,615
Interest Cost on Projected Benefit Obligation		3,603	3,363
Expected Return on Assets		(5,325)	(5,300)
From Regulatory Asset		1	4
From Other Comprehensive Income	[1]	2
From Regulatory Asset		1,163	1,784
From Other Comprehensive Income	[1]	27	44
Net Periodic Pension Cost	[2]	844	1,510
From Other Comprehensive Income	[1]	27	44
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		390	328
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		950	1,247
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		33	40
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		(150)	(21)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		(379)	(84)
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		105	100
Interest Cost on Projected Benefit Obligation		434	399
From Regulatory Asset		1	4
From Other Comprehensive Income	[3]	4	10
From Regulatory Asset		31	67
From Other Comprehensive Income	[3]	87	165
Net Periodic Pension Cost	[4]	662	745
From Other Comprehensive Income	[3]	87	165
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		26	25
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		79	75
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		557	645
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		321	382
Interest Cost on Projected Benefit Obligation		770	645
From Regulatory Asset		393	412
From Other Comprehensive Income	[1]	10	10
Net Periodic Pension Cost	[5]	1,494	1,449
From Other Comprehensive Income	[1]	10	10
Effect of Medicare Part D Subsidy		(45)	(37)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		91	78
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		223	294
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		7	10
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		333	217
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		$ 840	$ 850

[1] Corporate cost included in nonservice cost components of postretirement benefits.

[2] Allocation of Costs: Service costs included in OTP capital expenditures $ 390 $ 328 Service costs included in electric operation and maintenance expenses 950 1,247 Service costs included in other nonelectric expenses 33 40 Nonservice costs capitalized as regulatory assets (150 ) (21 ) Nonservice costs included in nonservice cost components of postretirement benefits (379 ) (84 )

[3] Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits.

[4] Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 25 Service costs included in other nonelectric expenses 79 75 Nonservice costs included in nonservice cost components of postretirement benefits 557 645

[5] Allocation of Costs: Service costs included in OTP capital expenditures $ 91 $ 78 Service costs included in electric operation and maintenance expenses 223 294 Service costs included in other nonelectric expenses 7 10 Nonservice costs capitalized as regulatory assets 333 217 Nonservice costs included in nonservice cost components of postretirement benefits 840 850

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Note 12 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Otter Tail Corporation Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.50%	1.50%
OTP Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.25%	1.25%

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Note 12 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 891	$ 861
Short-Term Debt	(43,601)	(18,599)
Long-Term Debt including Current Maturities	(590,196)	(590,174)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	891	861
Short-Term Debt	(43,601)	(18,599)
Long-Term Debt including Current Maturities	$ (611,219)	$ (601,513)

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Note 14 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2019 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 14 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Before Income Taxes	$ 31,952	$ 30,009
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	8,308	7,802
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates	(983)	(1,073)
Excess Tax Deduction – Equity Method Stock Awards	(827)	(624)
Corporate Owned Life Insurance	(409)	(8)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(258)
Research and Development and Other Tax Credits	(188)	(180)
Allowance for Funds Used During Construction – Equity	(86)	(167)
Federal Production Tax Credits (PTCs)		(1,120)
Other Comprehensive Income Deferred Tax Rate Adjustment		(531)
Other Items – Net	71	(47)
Income Tax Expense	$ 5,628	$ 3,794
Effective Income Tax Rate	17.60%	12.60%

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Note 14 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Composite Federal and State Statutory Rate	26.00%	26.00%

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Note 14 - Income Tax Expense - Continuing Operations - Unrecognized Tax Benefit Activity (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Balance, beginning	$ 1,282	$ 684
Increases Related to Tax Positions for Current Year	38	36
Uncertain Positions Resolved During Year		(44)
Balance, ending	$ 1,320	$ 676