Otter Tail (OTTR) 10-Q 8 May 20 2020 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2020	Apr. 30, 2020
Document Information [Line Items]
Entity Central Index Key	0001466593
Entity Registrant Name	Otter Tail Corp
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2020
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2020
Document Transition Report	false
Entity File Number	0-53713
Entity Incorporation, State or Country Code	MN
Entity Tax Identification Number	27-0383995
Entity Address, Address Line One	215 South Cascade Street, Box 496
Entity Address, City or Town	Fergus Falls
Entity Address, State or Province	MN
Entity Address, Postal Zip Code	56538-0496
City Area Code	866
Local Phone Number	410-8780
Title of 12(b) Security	Common Shares, par value $5.00 per share
Trading Symbol	OTTR
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		40,416,779

Consolidated Balance Sheets (Cu

Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Current Assets
Cash and Cash Equivalents	$ 7,884	$ 21,199
Accounts Receivable:
Trade—Net	96,158	77,947
Other	7,228	8,773
Inventories	98,152	97,851
Unbilled Receivables	19,057	20,911
Income Taxes Receivable	0	1,487
Regulatory Assets	20,358	21,650
Other	7,347	5,042
Total Current Assets	256,184	254,860
Investments	9,462	9,894
Other Assets	38,252	40,196
Goodwill	37,572	37,572
Other Intangibles—Net	10,993	11,290
Regulatory Assets	142,734	144,138
Right of Use Assets - Operating Leases	21,433	21,851
Plant
Electric Plant in Service	2,211,880	2,212,884
Nonelectric Operations	251,804	247,356
Construction Work in Progress	234,025	185,238
Total Gross Plant	2,697,709	2,645,478
Less Accumulated Depreciation and Amortization	908,337	891,684
Net Plant	1,789,372	1,753,794
Total Assets	2,306,002	2,273,595
Current Liabilities
Short-Term Debt	19,893	6,000
Current Maturities of Long-Term Debt	306	183
Accounts Payable	99,501	120,775
Accrued Salaries and Wages	14,889	22,730
Accrued Taxes	18,234	17,525
Regulatory Liabilities	9,804	7,480
Current Operating Lease Liabilities	4,197	4,136
Other Accrued Liabilities	8,864	10,912
Total Current Liabilities	175,688	189,741
Pensions Benefit Liability	87,214	98,970
Other Postretirement Benefits Liability	71,580	71,437
Long-Term Operating Lease Liabilities	17,755	18,193
Other Noncurrent Liabilities	30,912	30,833
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	137,816	131,941
Deferred Tax Credits	18,297	18,626
Regulatory Liabilities	239,108	239,906
Other	3,295	2,885
Total Deferred Credits	398,516	393,358
Capitalization
Long-Term Debt—Net	724,318	689,581
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2020—40,376,448 Shares; 2019—40,157,591 Shares	201,882	200,788
Premium on Common Shares	372,669	364,790
Retained Earnings	231,702	222,341
Accumulated Other Comprehensive Loss	(6,234)	(6,437)
Total Common Equity	800,019	781,482
Total Capitalization	1,524,337	1,471,063
Total Liabilities and Equity	2,306,002	2,273,595
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares	0	0
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares	$ 0	$ 0

Consolidated Balance Sheets (_2

Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares	Mar. 31, 2020	Dec. 31, 2019
Comm 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)	40,376,448	40,157,591
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

Consolidated Statements of Inco

Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating Revenues:
Total Operating Revenues	$ 234,747	$ 245,972
Operating Expenses
Production Fuel – Electric	13,735	18,920
Electric Operation and Maintenance Expenses	40,615	38,382
Cost of Products Sold (depreciation included below)	85,879	90,582
Other Nonelectric Expenses	11,900	13,477
Depreciation and Amortization	20,399	19,131
Property Taxes – Electric	4,100	3,959
Total Operating Expenses	195,458	206,403
Operating Income	39,289	39,569
Interest Charges	8,123	7,826
Nonservice Cost Components of Postretirement Benefits	871	1,035
Other (Loss) Income	(389)	1,244
Income Before Income Taxes	29,906	31,952
Income Tax Expense	5,638	5,628
Net Income	$ 24,268	$ 26,324
Average Number of Common Shares Outstanding—Basic (in shares)	40,217,141	39,657,321
Average Number of Common Shares Outstanding—Diluted (in shares)	40,444,336	39,903,165
Basic Earnings Per Common Share (in dollars per share)	$ 0.60	$ 0.66
Diluted Earnings Per Common Share (in dollars per share)	$ 0.60	$ 0.66
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 119,957	$ 129,144
Changes in Accrued Revenues under Alternative Revenue Programs	(87)	(1,049)
Total Electric Revenues	119,870	128,095
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	114,877	117,877
Electricity, Purchased [Member]
Operating Expenses
Purchased Power – Electric System Use	$ 18,830	$ 21,952

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Net Income	$ 24,268	$ 26,324
Unrealized Gains on Available-for-Sale Securities:
Reversal of Previously Recognized Losses on Available for Sale Securities Included in Other Income During Period	2	0
Unrealized Gains Arising During Period	126	91
Income Tax Expense	(27)	(19)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax	101	72
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	138	130
Income Tax Expense	(36)	(34)
Pension and Postretirement Benefit Plans – net-of-tax	102	96
Total Other Comprehensive Income	203	168
Total Comprehensive Income	$ 24,471	$ 26,492

Consolidated Statements of Comm

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, 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
Common Stock Retirements (in shares)	(55,224)
Common Stock Retirements	$ (276)	(2,454)			(2,730)
Net Income			26,324		26,324
Other Comprehensive Income				168	168
Employee Stock Incentive Plan Expense		1,796			1,796
Common Dividends			(13,922)		(13,922)
Common Stock Issuances, Net of Expenses		(601)
ASU 2018-02 2017 TCJA Stranded Tax Transfer			784	(784)
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
Balance (in shares) at Dec. 31, 2019	40,157,591
Balance at Dec. 31, 2019	$ 200,788	364,790	222,341	(6,437)	781,482
Common Stock Issuances, Net of Expenses (in shares)	257,074
Common Stock Issuances, Net of Expenses	$ 1,285	6,990			8,275
Common Stock Retirements (in shares)	(38,217)
Common Stock Retirements	$ (191)	(1,881)			(2,072)
Net Income			24,268		24,268
Other Comprehensive Income				203	203
Employee Stock Incentive Plan Expense		2,770			2,770
Common Dividends			(14,907)		(14,907)
Balance (in shares) at Mar. 31, 2020	40,376,448
Balance at Mar. 31, 2020	$ 201,882	$ 372,669	$ 231,702	$ (6,234)	$ 800,019

Consolidated Statements of Co_2

Consolidated Statements of Common Shareholders' Equity (Unaudited) (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Retained Earnings [Member]
Dividends declared per common share (in dollars per share)	$ 0.37	$ 0.35

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Operating Activities
Net Income	$ 24,268	$ 26,324
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization	20,399	19,131
Deferred Tax Credits	(329)	(337)
Deferred Income Taxes	5,812	835
Change in Deferred Debits and Other Assets	5,087	1,464
Discretionary Contribution to Pension Plan	(11,200)	(10,000)
Change in Noncurrent Liabilities and Deferred Credits	860	8,787
Allowance for Equity/Other Funds Used During Construction	(791)	(330)
Stock Compensation Expense	2,770	1,796
Other—Net	46	375
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(16,666)	(37,086)
Change in Inventories	(301)	(462)
Change in Other Current Assets	(447)	128
Change in Payables and Other Current Liabilities	(7,690)	4,088
Change in Interest and Income Taxes Receivable/Payable	(41)	2,437
Net Cash Provided by Operating Activities	21,777	17,150
Investing Activities
Capital Expenditures	(75,059)	(24,687)
Proceeds from Disposal of Noncurrent Assets	2,487	509
Cash Used for Investments and Other Assets	(2,487)	(1,258)
Net Cash Used in Investing Activities	(75,059)	(25,436)
Financing Activities
Change in Checks Written in Excess of Cash	0	8
Net Short-Term Borrowings	13,893	25,002
Proceeds from Issuance of Common Stock	8,399	0
Common Stock Issuance Expenses	(124)	0
Payments for Shares Withheld for Employee Tax Obligations	(2,072)	(2,730)
Proceeds from Issuance of Long-Term Debt	35,000	0
Short-Term and Long-Term Debt Issuance Expenses	(177)	0
Payments for Retirement of Long-Term Debt	(45)	(42)
Dividends Paid	(14,907)	(13,922)
Net Cash Provided by Financing Activities	39,967	8,316
Net Change in Cash and Cash Equivalents	(13,315)	30
Cash and Cash Equivalents at Beginning of Period	21,199	861
Cash and Cash Equivalents at End of Period	$ 7,884	$ 891

Note 1 - Summary of Significant

Note 1 - Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Significant Accounting Policies and New Accounting Pronouncements [Text Block]	1. 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 customer’s 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) Topic 606, Revenue from Contracts with Customers 606 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third 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), Energy Intensive Trade Exposed and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR, Phase-in Rate Plan 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 changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2020 2019. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 2020 2019. 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 Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may 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, 2020 December 31, 2019: March 31, 20 20 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,130 Corporate Debt Securities – Held by Captive Insurance Company $ 2,842 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 5,379 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,526 Total Assets $ 3,656 $ 8,221 December 31, 20 19 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,586 Corporate Debt Securities – Held by Captive Insurance Company $ 2,124 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 6,060 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,363 Total Assets $ 3,949 $ 8,184 The level 2 third may Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2020. Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2020 2019 Finished Goods $ 29,996 $ 31,863 Work in Process 15,811 16,508 Raw Material, Fuel and Supplies 52,345 49,480 Total Inventories $ 98,152 $ 97,851 Intangible Assets 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, 2020 December 31, 2019: March 31, 20 20 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,543 $ 10,948 85 - 185 Other 179 134 45 5 - 42 Total $ 22,670 $ 11,677 $ 10,993 December 31, 20 19 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,259 $ 11,232 88 - 188 Other 179 121 58 8 - 45 Total $ 22,670 $ 11,380 $ 11,290 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2020 2019 Amortization Expense – Intangible Assets $ 296 $ 296 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2020 2021 2022 2023 2024 Estimated Amortization Expense – Intangible Assets $ 1,140 $ 1,105 $ 1,105 $ 1,104 $ 1,099 Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2020 2019 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,193 $ 4,338 New Accounting Standards Adopted ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , December 31, 2019. may 326 first 2020. not not Accounting Policy Trade account and unbilled receivables reflected in the Company’s consolidated balance sheets represent the net amounts expected to be collected. An allowance for credit losses is established based on expected losses. Expected losses are estimated by reviewing individual accounts, considering aging, financial condition of the debtor for certain accounts, recent payment history, current and forecasted economic conditions and other relevant factors. Allowance for Credit Losses Following is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company: Three Months Ended March 31, (in thousands) 2020 2019 Beginning Balance $ 1,339 $ 1,407 Additions Charged to Expense (net of recoveries) 635 247 Reductions for Amounts Written Off (293 ) (121 ) Ending Balance $ 1,681 $ 1,533 ASU 2018 15 August 2018 No. 2018 15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350 40 350 40, Internal-Use Software 2018 15 2018 15 350 40 2018 15 2018 15 December 15, 2019 2018 15 first 2020. no

Note 2 - Segment Information

Note 2 - Segment Information	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Segment Reporting Disclosure [Text Block]	2. Segment Information The accounting policies of the segments are described under note 1 three Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation. 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 While no single customer accounted for over 10% 2019, 2019 2019 2019 2019 2019 2019 one All of the Company’s long-lived assets are within the United States and 99.1% and 99.0% of its operating revenues for the respective three March 31, 2020 2019 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 March 31, 2020 2019 March 31, 2020 December 31, 2019 Operating Revenue Three Months Ended March 31, (in thousands) 2020 2019 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 106,690 $ 114,955 Changes in Accrued ARP Revenues (87 ) (1,049 ) Total Retail Sales Revenue 106,603 113,906 Transmission Services Revenue 10,841 10,862 Wholesale Revenues – Company Generation 876 1,527 Other Revenues 1,556 1,814 Total Electric Segment Revenues 119,876 128,109 Manufacturing Segment: Metal Parts and Tooling 57,211 66,724 Plastic Products and Tooling 9,883 9,045 Other 1,385 2,053 Total Manufacturing Segment Revenues 68,479 77,822 Plastics Segment – Sale of PVC Pipe Products 46,397 40,058 Intersegment Eliminations (5 ) (17 ) Total $ 234,747 $ 245,972 Interest Charges Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 7,384 $ 6,641 Manufacturing 554 584 Plastics 148 149 Corporate and Intersegment Eliminations 37 452 Total $ 8,123 $ 7,826 Income Taxes Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 3,620 $ 4,771 Manufacturing 1,461 1,454 Plastics 1,917 1,329 Corporate (1,360 ) (1,926 ) Total $ 5,638 $ 5,628 Net Income (Loss) Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 16,182 $ 18,700 Manufacturing 4,927 4,842 Plastics 5,449 3,729 Corporate (2,290 ) (947 ) Total $ 24,268 $ 26,324 Identifiable Assets March 31, December 31, (in thousands) 2020 2019 Electric $ 1,955,465 $ 1,931,525 Manufacturing 201,892 195,742 Plastics 102,654 92,049 Corporate 45,991 54,279 Total $ 2,306,002 $ 2,273,595

Note 3 - Rate and Regulatory Ma

Note 3 - Rate and Regulatory Matters	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Public Utilities Disclosure [Text Block]	3. Below are descriptions of OTP’s major capital expenditure projects that 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 2020 2019. Major Capital Expenditure Projects Merricourt Wind Energy Center (Merricourt) November 16, 2016 150 November 16, 2016, 2020 June 11, 2019, July 16, 2019 August 2019. April 2019. With the NDPSC’s March 18, 2020 three March 31, 2020, 19 not December 31, 2020. not December 31, 2020, Astoria Station 2021. November 3, 2017, August 3, 2018 September 26, 2018 March 6, 2019 December 2018 January 2019. May 2019, March 31, 2020, 2020 2021. General Rates Minnesota 2016 March 2017 May 1, 2017. The MPUC’s order also included: ( 1 2 November 1, 2017. North Dakota March 23, 2018 In a September 26, 2018 2017 February 1, 2019, April 2019 January February 2018. South Dakota April 20, 2018 first two October 18, 2018. second March 1, 2019 second January 1, 2018 October 17, 2018 first 2019. May 14, 2019 May 30, 2019 August 1, 2019. October 18, 2018 October 2019 On July 9, 2019 May 30, 2019 first October 18, 2018, October 1, 2019. To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 9.50% 30 Rate Riders In addition to general rates, OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR, Phase-in Rate Plan and Energy Efficiency Plan (conservation) riders. Following is a brief summary of recent proceedings of riders in place in each state served by OTP, followed by tables showing revenues recorded under rate riders for the three March 31, 2020 March 31, 2019 2020 2019. 10 December 31, 2019. Minnesota Minnesota Conservation Improvement Programs (MNCIP) May 1, 2020 2019 2019 not Transmission Cost Recovery Rider 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 On November 30, 2018 two two April 1, 2019, April 22, 2020, not March 31, 2020 Renewable Resource Adjustment June 21, 2019 December 19, 2019 Fuel and Purchased Power Costs Recovery December 2017 October 31, 2019 2020 January 1, 2020. North Dakota Renewable Resource Adjustment December 31, 2019 November 30, 2019. February 25, 2020 March 18, 2020. 25 10 Generation Cost Recovery Rider May 15, 2019 July 1, 2019. South Dakota Phase-In Rate Plan Rider May 31, 2019 August 21, 2019 September 1, 2019. 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 March 31: Rate Rider (in thousands) 2020 2019 Minnesota Renewable Resource Recovery $ 3,254 $ 1,316 Conservation Improvement Program Costs and Incentives 1,086 887 Transmission Cost Recovery 715 641 Environmental Cost Recovery - (1 ) North Dakota Transmission Cost Recovery 1,482 1,772 Renewable Resource Adjustment 1,129 729 Generation Cost Recovery 948 248 Environmental Cost Recovery - 575 South Dakota Phase-In Rate Plan 646 - Transmission Cost Recovery 562 473 Conservation Improvement Program Costs and Incentives 344 244 Environmental Cost Recovery - (4 ) Total $ 10,166 $ 6,880 Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2018 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2019 Incentive and Cost Recovery R – May 1, 2020 October 1, 2020 $ 8,247 $0.00485 /kwh 2018 Incentive and Cost Recovery A – December 27, 2019 January 1, 2020 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /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 Renewable Resource Adjustment 2019 Annual Update – Revised A – December 19, 2019 January 1, 2020 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh North Dakota Renewable Resource Adjustment 2020 Annual Update A – March 18, 2020 April 1, 2020 $ 5,762 5.637% of base 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 Transmission Cost Recovery 2019 Annual Update A – December 18, 2019 January 1, 2020 $ 5,739 Various 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 Environmental Cost Recovery 2019 Update A – October 22, 2019 November 1, 2019 $ - 0% of base 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 Generation Cost Recovery 2020 Annual Update R – March 2, 2020 July 1, 2020 $ 6,184 6.041% of base 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2020 Annual Update A – February 19, 2020 March 1, 2020 $ 2,327 Various 2019 Rate Reset A – September 17, 2019 October 1, 2019 $ 2,046 Various 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 Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh Phase-In Rate Plan Recovery 2019 Initial Request A – August 21, 2019 September 1, 2019 $ 864 3.345% of base FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 MVPs ROE November 12, 2013 may 15 November 12, 2013 February 11, 2015. December 22, 2015 September 28, 2016 September 2016 On November 6, 2014 January 5, 2015 November 12, 2013 0.5% September 28, 2016. On February 12, 2015 may 12.38% second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 On November 21, 2019 two 206 9.88%. two first 12.38% September 28, 2016, second not 9.88% first OTP has accrued a MISO Tariff ROE refund liability of $3.0 million as of March 31, 2020. ● a $0.2 million refund related to the first 10.32%, September 28, 2016 9.88% ● a $1.3 million refund for the period from September 28, 2016 December 31, 2019 9.88% first January 5, 2015, ● a $1.5 million refund related to the second second In response to the FERC’s November 21, 2019 November 21, 2019

Note 4 - Regulatory Assets and

Note 4 - Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Schedule of Regulatory Assets and Liabilities [Text Block]	4. As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. 980 605 25 March 31, 2020 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,018 $ 127,038 $ 136,056 see below Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment 1 - 8,007 8,007 asset lives Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 5,965 - 5,965 12 Conservation Improvement Program Costs and Incentives 2 1,288 3,511 4,799 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups 1 1,767 928 2,695 21 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,826 1,826 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 724 38 762 13 Debt Reacquisition Premiums 1 204 482 686 150 Deferred Marked-to-Market Losses 1 557 - 557 9 Big Stone II Unrecovered Project Costs – South Dakota 1 144 217 361 30 Minnesota Renewable Resource Rider Accrued Revenues 2 354 - 354 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 138 211 349 31 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 122 213 335 33 Minnesota SPP Transmission Cost Recovery Tracker 1 - 206 206 see below South Dakota Phase-In Rate Plan Rider Accrued Revenues 2 73 - 73 12 Deferred Lease Expenses 1 - 57 57 36 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 Total Regulatory Assets $ 20,358 $ 142,734 $ 163,092 Regulatory Liabilities: Deferred Income Taxes $ - $ 140,112 $ 140,112 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 98,465 98,465 asset lives Refundable Fuel Clause Adjustment Revenues 8,078 - 8,078 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 662 - 662 12 Prior Service Costs and Actuarial Gains on Postretirement Benefits 471 - 471 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 460 460 see below North Dakota Renewable Resource Recovery Rider Accrued Refund 325 - 325 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 201 - 201 11 South Dakota Transmission Cost Recovery Rider Accrued Refund 33 - 33 11 North Dakota Generation Cost Recovery Rider Accrued Refund 28 - 28 12 Other 6 71 77 165 Total Regulatory Liabilities $ 9,804 $ 239,108 $ 248,912 Net Regulatory Asset/(Liability) Position $ 10,554 $ (96,374 ) $ (85,820 ) 1 2 December 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 $ 9,090 $ 129,102 $ 138,192 see below Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment 1 - 7,772 7,772 asset lives Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 4,208 - 4,208 12 Conservation Improvement Program Costs and Incentives 2 4,024 2,844 6,868 21 MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups 1 2,033 968 3,001 24 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,681 1,681 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 715 225 940 16 Debt Reacquisition Premiums 1 201 548 749 153 Deferred Marked-to-Market Losses 1 743 - 743 12 Big Stone II Unrecovered Project Costs – South Dakota 1 144 253 397 33 Minnesota Renewable Resource Rider Accrued Revenues 2 131 - 131 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 138 245 383 34 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 122 244 366 36 Minnesota SPP Transmission Cost Recovery Tracker 1 - 202 202 see below Deferred Lease Expenses 1 - 54 54 39 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 97 - 97 2 Total Regulatory Assets $ 21,650 $ 144,138 $ 165,788 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,707 $ 141,707 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 97,726 97,726 asset lives Refundable Fuel Clause Adjustment Revenues 3,982 - 3,982 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 700 - 700 12 Prior Service Costs and Actuarial Gains on Postretirement Benefits 471 - 471 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 401 401 see below North Dakota Renewable Resource Recovery Rider Accrued Refund 1,515 - 1,515 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 164 - 164 12 North Dakota Generation Cost Recovery Rider Accrued Refund 287 - 287 6 Other 6 72 78 168 South Dakota Phase-In Rate Plan Rider Accrued Refund 355 - 355 9 Total Regulatory Liabilities $ 7,480 $ 239,906 $ 247,386 Net Regulatory Asset/(Liability) Position $ 14,170 $ (95,768 ) $ (81,598 ) 1 2 The regulatory asset and liability related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses and gains subject to recovery or refund through rates as they are expensed. These unrecognized benefit costs and actuarial losses and gains are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits The Accumulated ARO Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. 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 were recoverable from Minnesota customers as of the balance sheet date. Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. MISO Schedule 26/26A 26/26A 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. Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 150 All Deferred Marked-to-Market Losses recorded as of the balance sheet date relate to forward purchases of energy scheduled for delivery through December 2020. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date. South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018. The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that had not The South Dakota Phase-In Rate Plan Rider Accrued Revenues relate to revenues earned for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were recoverable from South Dakota customers as of the balance sheet date. Deferred Lease Expenses: Under ASC 842 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 were recoverable from Minnesota customers as of the balance sheet date. The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date. The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The 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 were refundable to North Dakota customers as of the balance sheet date. 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 North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that were refundable to North Dakota customers as of the balance sheet date. The Minnesota Energy Intensive Trade Exposed Rider Accrued Refund relates to over-collected amounts from Minnesota retail customers for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to refund to Minnesota customers as of the balance sheet date. 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 were refundable to South Dakota customers as of the balance sheet date. The North Dakota Generation Cost Recovery Rider Accrued Refund relates to revenues collected under the rider in excess of returns allowed on recoverable costs incurred for 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 balance represents amounts subject to refund to North Dakota customers that had been billed to North Dakota customers as of the balance sheet date. The South Dakota Phase-In Rate Plan Rider Accrued Refund relates to amounts collected for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to South Dakota customers as of the balance sheet date. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980

Note 5 - Common Shares and Earn

Note 5 - Common Shares and Earnings Per Share	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Stockholders Equity and Earnings per Share [Text Block]	5. Shelf Registration On May 3, 2018 may May 3, 2021. On November 8, 2019, may Under the Distribution Agreement, the Company will designate the minimum price and maximum number of common shares to be sold through KeyBanc on any given trading day or over a specified period of trading days, and KeyBanc will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales of the shares, if any, will be made by means of ordinary brokers’ transactions on the Nasdaq Global Select Market at market prices or as otherwise agreed with KeyBanc. The Company may not not 2020 Following is a reconciliation of the Company’s common shares outstanding from December 31, 2019 March 31, 2020: Common Shares Outstanding, December 31, 2019 40,157,591 Issuances: At-the-Market Offering 112,380 Executive Stock Performance Awards (2017 awards earned) 62,497 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 30,677 Cash Invested 12,772 Vesting of Restricted Stock Units 23,000 Employee Stock Purchase Plan: Cash Invested 13,432 Dividends Reinvested 2,316 Retirements: Shares Withheld for Individual Income Tax Requirements (38,217 ) Common Shares Outstanding, March 31, 2020 40,376,448 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income with no three March 31, 2020 2019. not three March 31: 2020 2019 Weighted Average Common Shares Outstanding – Basic 40,217,141 39,657,321 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 125,637 158,159 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 63,897 63,398 Nonvested Restricted Shares 19,861 21,922 Shares Expected to be Issued Under the Employee Stock Purchase Plan 15,977 - Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,823 2,365 Total Dilutive Shares 227,195 245,844 Weighted Average Common Shares Outstanding – Diluted 40,444,336 39,903,165 The effect of dilutive shares on earnings per share for the three March 31, 2020 2019, no $0.01

Note 6 - Share-based Payments

Note 6 - Share-based Payments	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Share-based Payment Arrangement [Text Block]	6. Stock Incentive Awards The following stock incentive awards were granted under the 2014 three March 31, 2020. Award Grant Date Shares/ Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Restricted Stock Units Granted: To Key Management Employees February 3, 2020 3,000 $ 54.0450 25% per year through February 6, 2024 To Executive Officers February 12, 2020 15,300 $ 54.0607 25% per year through February 6, 2024 Stock Performance Awards Granted: Under Executive Agreement February 12, 2020 47,600 $ 47.10 December 31, 2022 Under Legacy Agreement February 12, 2020 7,400 $ 52.20 December 31, 2022 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. Restricted stock units granted to executive officers and certain key employees 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 55,000 shares. For target performance the participants would earn an aggregate of 27,500 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,500 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, 2020 December 31, 2022, January 1, 2020 20 January 1, 2023. may zero no 718, Compensation – Stock Compensation Under the 2020 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, 2020, Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three March 31, 2020 2019 Three months ended March 31, (in thousands) 2020 2019 Stock Performance Awards Granted to Executive Officers $ 1,700 $ 1,113 Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees 679 427 Restricted Stock Granted to Directors 204 165 Restricted Stock Units Granted to Non-Executive Employees 134 91 ESPP (15% discount) 53 - Totals $ 2,770 $ 1,796

Note 7 - Retained Earnings and

Note 7 - Retained Earnings and Dividend Restriction	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Retained Earnings Restrictions [Text Block]	7. The Company is a holding company with no 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 March 31, 2020, Under the Federal Power Act, a public utility may not 1 2 not 3 no The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 46.0% and 56.2% based on OTP’s 2019 July 19, 2019. March 31, 2020, 2019

Note 8 - Leases

Note 8 - Leases	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Lessee, Operating Leases [Text Block]	8. No

Note 9 - Commitments and Contin

Note 9 - Commitments and Contingencies	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	9. Construction and Other Purchase Commitments At March 31, 2020 December 31, 2019 On October 1, 2019 six January 1, 2020. no not six 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 2043. 2040. 2020. December 31, 2020. no December 31, 2023, no OTP Land Easements OTP has commitments to make future payments for land easements not 2034 Contingencies OTP had a $3.0 million refund liability on its balance sheet as of March 31, 2020. 3 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, risks associated with adverse regulatory decisions that could impact the recovery of fixed asset costs in future rates and litigation matters. On August 30, 2019 seven State implementation of pollution control plans to improve visibility and air quality at national parks under the EPA’s Regional Haze Rule (RHR) could require OTP to incur significant new costs, which could, dependent on determinations by state regulatory commissions on approval to recover such costs from customers, negatively impact OTP’s and the Company’s net income, financial position and cash flows. OTP understands that the North Dakota Department of Environmental Quality (NDDEQ) intends to require sources subject to RHR Round 2 1. December 31, 2028 July 2021. March 3, 2020 2 2020. may not 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, 2020, not

Note 10 - Short-term and Long-t

Note 10 - Short-term and Long-term Borrowings	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Debt Disclosure [Text Block]	10. The following table presents the status of the Company’s lines of credit as of March 31, 2020 December 31, 2019: (in thousands) Line Limit In Use on March 31, 2020 Restricted due to Outstanding Letters of Credit Available on March 31, 2020 Available on December 31, 2019 Otter Tail Corporation Credit Agreement $ 170,000 $ 19,893 $ - $ 150,107 $ 164,000 OTP Credit Agreement 170,000 - 14,101 155,899 154,524 Total $ 340,000 $ 19,893 $ 14,101 $ 306,006 $ 318,524 Long-Term Debt Issuances 201 9 Note Purchase Agreement On September 12, 2019, 2019 2019A October 10, 2029 ( 2019A 2019B October 10, 2039 ( 2019B 2019C October 10, 2049 ( 2019C 2020A February 25, 2030 ( 2020A 2020B August 20, 2030 ( 2020B 2020C February 25, 2040 ( 2020C 2020D February 25, 2050 ( 2020D 2019A 2019B 2019C 2020A 2020B 2020C On February 25, 2020, 2020A 2020C 2020D 2019 2019A 2019B 2019C October 10, 2019. 2020B, August 20, 2020, OTP may not no 2019 2020A August 25, 2029, 2020C August 25, 2039 2020D August 25, 2049 2019 100% 2019 The 2019 2019 may not 2019 2019 2019 not 2019 not 2019 2019 2019 2019 2019 no 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, 2020 December 31, 2019: March 31, 20 20 (in thousands) OTP Otter Tail Corporation Consolidated Short-Term Debt $ - $ 19,893 $ 19,893 Long-Term Debt: 3.55% December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63% December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15% August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37% August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68% February 27, 2029 60,000 60,000 Senior Unsecured Notes 3.07% October 10, 2029 1 10,000 10,000 Senior Unsecured Notes 3.22% February 25, 2030 10,000 10,000 Senior Unsecured Notes 6.47% August 20, 2037 50,000 50,000 Senior Unsecured Notes 3.52% October 10, 2039 26,000 26,000 Senior Unsecured Notes 3.62% February 25, 2040 10,000 10,000 Senior Unsecured Notes 5.47% February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07% February 7, 2048 100,000 100,000 Senior Unsecured Notes 3.82% October 10, 2049 64,000 64,000 Senior Unsecured Notes 3.92% February 25, 2050 15,000 15,000 PACE Note, 2.54% March 18, 2021 306 306 Total $ 647,000 $ 80,306 $ 727,306 Less: Current Maturities net of Unamortized Debt Issuance Costs - 306 306 Unamortized Long-Term Debt Issuance Costs 2,339 343 2,682 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 644,661 $ 79,657 $ 724,318 Total Short-Term and Long-Term Debt (with current maturities) $ 644,661 $ 99,856 $ 744,517 December 31, 2019 (in thousands) Short-Term Debt $ - $ 6,000 $ 6,000 Long-Term Debt: 3.55% December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63% December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15% August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37% August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68% February 27, 2029 60,000 60,000 Senior Unsecured Notes 3.07% October 10, 2029 1 10,000 10,000 Senior Unsecured Notes 6.47% August 20, 2037 50,000 50,000 Senior Unsecured Notes 3.52% October 10, 2039 26,000 26,000 Senior Unsecured Notes 5.47% February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07% February 7, 2048 100,000 100,000 Senior Unsecured Notes 3.82% October 10, 2049 64,000 64,000 PACE Note, 2.54% March 18, 2021 351 351 Total $ 612,000 $ 80,351 $ 692,351 Less: Current Maturities net of Unamortized Debt Issuance Costs - 183 183 Unamortized Long-Term Debt Issuance Costs 2,231 356 2,587 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 609,769 $ 79,812 $ 689,581 Total Short-Term and Long-Term Debt (with current maturities) $ 609,769 $ 85,995 $ 695,764 1 may

Note 11 - Pension Plan and Othe

Note 11 - Pension Plan and Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Retirement Benefits [Text Block]	1 1 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 1,655 $ 1,373 Interest Cost on Projected Benefit Obligation 3,263 3,603 Expected Return on Assets (5,505 ) (5,325 ) Amortization of Prior-Service Cost: From Regulatory Asset - 1 From Other Comprehensive Income 1 - 2 Amortization of Net Actuarial Loss: From Regulatory Asset 2,231 1,163 From Other Comprehensive Income 1 55 27 Net Periodic Pension Cost 2 $ 1,699 $ 844 1 n onservice c ost c omponents of p ostretirement b enefits . 2 c osts: Service c osts included in OTP c apital e xpenditures $ 423 $ 390 Service c osts included in e lectric o peration and m aintenance e xpenses 1,192 950 Service c osts included in o ther n onelectric e xpenses 40 33 Nonservice costs capitalized as regulatory assets 11 (150 ) Nonservice costs included in n onservice cost components of postretirement benefits 33 (379 ) Cash flows no December 31, 2019 January 2020. Executive Survivor and Supplemental Retirement Plan Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 45 $ 105 Interest Cost on Projected Benefit Obligation 362 434 Amortization of Prior Service Cost: From Regulatory Asset - 1 From Other Comprehensive Income 1 - 4 Amortization of Net Actuarial Loss: From Regulatory Asset 23 31 From Other Comprehensive Income 1 86 87 Net Periodic Pension Cost 2 $ 516 $ 662 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 Service c osts included in e lectric o peration and m aintenance e xpenses $ - $ 26 Service costs included in ot her n onelectric e xpenses 45 79 Nonservice c osts included in n onservice cost components of postretirement benefits 471 557 Other Postretirement Benefits Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 462 $ 321 Interest Cost on Projected Benefit Obligation 598 770 Amortization of Prior-Service Cost: From Regulatory Asset (1,169 ) - From Other Comprehensive Income 1 (29 ) - Amortization of Net Actuarial Loss: From Regulatory Asset 1,051 393 From Other Comprehensive Income 1 26 10 Net Periodic Postretirement Benefit Cost 2 $ 939 $ 1,494 Effect of Medicare Part D Subsidy $ 281 $ (45 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Service c osts included in OTP capital expenditures $ 118 $ 91 Service costs included in electric operation and maintenance expenses 333 223 Service costs included in other nonelectric expenses 11 7 Nonservice costs capitalized as regulatory assets 122 333 Nonservice costs included in n onservice cost components of postretirement benefits 355 840

Note 12 - Fair Value of Financi

Note 12 - Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2020
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 Short-Term Debt March 31, 2020 December 31, 2019 Long-Term Debt including Current Maturities 2 820. March 31, 2020 December 31, 2019 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 7,884 $ 7,884 $ 21,199 $ 21,199 Short-Term Debt (19,893 ) (19,893 ) (6,000 ) (6,000 ) Long-Term Debt including Current Maturities (724,624 ) (759,980 ) (689,764 ) (742,279 )

Note 13 - Property, Plant and E

Note 13 - Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2020
Notes to Financial Statements
Property, Plant and Equipment Disclosure [Text Block]	13. No

Note 14 - Income Tax Expense

Note 14 - Income Tax Expense	3 Months Ended
	Mar. 31, 2020
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 March 31, 2020 2019: Three Months Ended March 31, (in thousands) 2020 2019 Income Before Income Taxes $ 29,906 $ 31,952 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) 7,776 8,308 Increases (Decreases) in Tax from: Differences Reversing in Excess of Federal Rates (1,229 ) (983 ) Excess Tax Deduction – Equity Method Stock Awards (402 ) (827 ) Allowance for Funds Used During Construction – Equity (312 ) (86 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) Research and Development and Other Tax Credits (54 ) (188 ) Corporate Owned Life Insurance 207 (409 ) Other Items – Net (90 ) 71 Income Tax Expense $ 5,638 $ 5,628 Effective Income Tax Rate 18.9 % 17.6 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2020 2019 Balance on January 1 $ 1,488 $ 1,282 Increases Related to Tax Positions for Current Year 41 38 Uncertain Positions Resolved During Year - - Balance on March 31 $ 1,529 $ 1,320 The balance of unrecognized tax benefits as of March 31, 2020 March 31, 2020 12 The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of May 1, 2020, no 2016

Significant Accounting Policies

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2020
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 customer’s 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) Topic 606, Revenue from Contracts with Customers 606 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third 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), Energy Intensive Trade Exposed and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, Renewable Resource Cost Recovery and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR, Phase-in Rate Plan 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 changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2020 2019. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 2020 2019.
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
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may 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, 2020 December 31, 2019: March 31, 20 20 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,130 Corporate Debt Securities – Held by Captive Insurance Company $ 2,842 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 5,379 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,526 Total Assets $ 3,656 $ 8,221 December 31, 20 19 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,586 Corporate Debt Securities – Held by Captive Insurance Company $ 2,124 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 6,060 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,363 Total Assets $ 3,949 $ 8,184 The level 2 third may
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2020.
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) 2020 2019 Finished Goods $ 29,996 $ 31,863 Work in Process 15,811 16,508 Raw Material, Fuel and Supplies 52,345 49,480 Total Inventories $ 98,152 $ 97,851
Goodwill and Intangible Assets, Policy [Policy Text Block]	Intangible Assets 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, 2020 December 31, 2019: March 31, 20 20 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,543 $ 10,948 85 - 185 Other 179 134 45 5 - 42 Total $ 22,670 $ 11,677 $ 10,993 December 31, 20 19 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,259 $ 11,232 88 - 188 Other 179 121 58 8 - 45 Total $ 22,670 $ 11,380 $ 11,290 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2020 2019 Amortization Expense – Intangible Assets $ 296 $ 296 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2020 2021 2022 2023 2024 Estimated Amortization Expense – Intangible Assets $ 1,140 $ 1,105 $ 1,105 $ 1,104 $ 1,099
Cash Flow Supplemental [Policy Text Block]	Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2020 2019 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,193 $ 4,338
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Standards Adopted ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , December 31, 2019. may 326 first 2020. not not Accounting Policy Trade account and unbilled receivables reflected in the Company’s consolidated balance sheets represent the net amounts expected to be collected. An allowance for credit losses is established based on expected losses. Expected losses are estimated by reviewing individual accounts, considering aging, financial condition of the debtor for certain accounts, recent payment history, current and forecasted economic conditions and other relevant factors. Allowance for Credit Losses Following is a summary of activity in allowances for credit losses on trade and unbilled accounts receivable across the Company: Three Months Ended March 31, (in thousands) 2020 2019 Beginning Balance $ 1,339 $ 1,407 Additions Charged to Expense (net of recoveries) 635 247 Reductions for Amounts Written Off (293 ) (121 ) Ending Balance $ 1,681 $ 1,533 ASU 2018 15 August 2018 No. 2018 15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350 40 350 40, Internal-Use Software 2018 15 2018 15 350 40 2018 15 2018 15 December 15, 2019 2018 15 first 2020. no

Note 1 - Summary of Significa_2

Note 1 - Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	March 31, 20 20 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,130 Corporate Debt Securities – Held by Captive Insurance Company $ 2,842 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 5,379 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,526 Total Assets $ 3,656 $ 8,221 December 31, 20 19 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,586 Corporate Debt Securities – Held by Captive Insurance Company $ 2,124 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 6,060 Other Assets: Money Market and Mutual Funds –Retirement Plans 2,363 Total Assets $ 3,949 $ 8,184
Schedule of Inventory, Current [Table Text Block]	March 31, December 31, (in thousands) 2020 2019 Finished Goods $ 29,996 $ 31,863 Work in Process 15,811 16,508 Raw Material, Fuel and Supplies 52,345 49,480 Total Inventories $ 98,152 $ 97,851
Schedule of Finite-Lived Intangible Assets [Table Text Block]	March 31, 20 20 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,543 $ 10,948 85 - 185 Other 179 134 45 5 - 42 Total $ 22,670 $ 11,677 $ 10,993 December 31, 20 19 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 11,259 $ 11,232 88 - 188 Other 179 121 58 8 - 45 Total $ 22,670 $ 11,380 $ 11,290
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	Three Months Ended March 31, (in thousands) 2020 2019 Amortization Expense – Intangible Assets $ 296 $ 296
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	(in thousands) 2020 2021 2022 2023 2024 Estimated Amortization Expense – Intangible Assets $ 1,140 $ 1,105 $ 1,105 $ 1,104 $ 1,099
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	As of March 31, (in thousands) 2020 2019 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,193 $ 4,338
Accounts Receivable, Allowance for Credit Loss [Table Text Block]	Three Months Ended March 31, (in thousands) 2020 2019 Beginning Balance $ 1,339 $ 1,407 Additions Charged to Expense (net of recoveries) 635 247 Reductions for Amounts Written Off (293 ) (121 ) Ending Balance $ 1,681 $ 1,533

Note 2 - Segment Information (T

Note 2 - Segment Information (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended March 31, (in thousands) 2020 2019 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 106,690 $ 114,955 Changes in Accrued ARP Revenues (87 ) (1,049 ) Total Retail Sales Revenue 106,603 113,906 Transmission Services Revenue 10,841 10,862 Wholesale Revenues – Company Generation 876 1,527 Other Revenues 1,556 1,814 Total Electric Segment Revenues 119,876 128,109 Manufacturing Segment: Metal Parts and Tooling 57,211 66,724 Plastic Products and Tooling 9,883 9,045 Other 1,385 2,053 Total Manufacturing Segment Revenues 68,479 77,822 Plastics Segment – Sale of PVC Pipe Products 46,397 40,058 Intersegment Eliminations (5 ) (17 ) Total $ 234,747 $ 245,972 Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 7,384 $ 6,641 Manufacturing 554 584 Plastics 148 149 Corporate and Intersegment Eliminations 37 452 Total $ 8,123 $ 7,826 Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 3,620 $ 4,771 Manufacturing 1,461 1,454 Plastics 1,917 1,329 Corporate (1,360 ) (1,926 ) Total $ 5,638 $ 5,628 Three Months Ended March 31, (in thousands) 2020 2019 Electric $ 16,182 $ 18,700 Manufacturing 4,927 4,842 Plastics 5,449 3,729 Corporate (2,290 ) (947 ) Total $ 24,268 $ 26,324 March 31, December 31, (in thousands) 2020 2019 Electric $ 1,955,465 $ 1,931,525 Manufacturing 201,892 195,742 Plastics 102,654 92,049 Corporate 45,991 54,279 Total $ 2,306,002 $ 2,273,595

Note 3 - Rate and Regulatory _2

Note 3 - Rate and Regulatory Matters (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Revenues Recorded under Rate Riders [Table Text Block]	Rate Rider (in thousands) 2020 2019 Minnesota Renewable Resource Recovery $ 3,254 $ 1,316 Conservation Improvement Program Costs and Incentives 1,086 887 Transmission Cost Recovery 715 641 Environmental Cost Recovery - (1 ) North Dakota Transmission Cost Recovery 1,482 1,772 Renewable Resource Adjustment 1,129 729 Generation Cost Recovery 948 248 Environmental Cost Recovery - 575 South Dakota Phase-In Rate Plan 646 - Transmission Cost Recovery 562 473 Conservation Improvement Program Costs and Incentives 344 244 Environmental Cost Recovery - (4 ) Total $ 10,166 $ 6,880
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 Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2019 Incentive and Cost Recovery R – May 1, 2020 October 1, 2020 $ 8,247 $0.00485 /kwh 2018 Incentive and Cost Recovery A – December 27, 2019 January 1, 2020 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /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 Renewable Resource Adjustment 2019 Annual Update – Revised A – December 19, 2019 January 1, 2020 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh North Dakota Renewable Resource Adjustment 2020 Annual Update A – March 18, 2020 April 1, 2020 $ 5,762 5.637% of base 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 Transmission Cost Recovery 2019 Annual Update A – December 18, 2019 January 1, 2020 $ 5,739 Various 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 Environmental Cost Recovery 2019 Update A – October 22, 2019 November 1, 2019 $ - 0% of base 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 Generation Cost Recovery 2020 Annual Update R – March 2, 2020 July 1, 2020 $ 6,184 6.041% of base 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2020 Annual Update A – February 19, 2020 March 1, 2020 $ 2,327 Various 2019 Rate Reset A – September 17, 2019 October 1, 2019 $ 2,046 Various 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 Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh Phase-In Rate Plan Recovery 2019 Initial Request A – August 21, 2019 September 1, 2019 $ 864 3.345% of base

Note 4 - Regulatory Assets an_2

Note 4 - Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Regulatory Assets and Liabilities [Table Text Block]	March 31, 2020 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,018 $ 127,038 $ 136,056 see below Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment 1 - 8,007 8,007 asset lives Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 5,965 - 5,965 12 Conservation Improvement Program Costs and Incentives 2 1,288 3,511 4,799 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups 1 1,767 928 2,695 21 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,826 1,826 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 724 38 762 13 Debt Reacquisition Premiums 1 204 482 686 150 Deferred Marked-to-Market Losses 1 557 - 557 9 Big Stone II Unrecovered Project Costs – South Dakota 1 144 217 361 30 Minnesota Renewable Resource Rider Accrued Revenues 2 354 - 354 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 138 211 349 31 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 122 213 335 33 Minnesota SPP Transmission Cost Recovery Tracker 1 - 206 206 see below South Dakota Phase-In Rate Plan Rider Accrued Revenues 2 73 - 73 12 Deferred Lease Expenses 1 - 57 57 36 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 Total Regulatory Assets $ 20,358 $ 142,734 $ 163,092 Regulatory Liabilities: Deferred Income Taxes $ - $ 140,112 $ 140,112 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 98,465 98,465 asset lives Refundable Fuel Clause Adjustment Revenues 8,078 - 8,078 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 662 - 662 12 Prior Service Costs and Actuarial Gains on Postretirement Benefits 471 - 471 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 460 460 see below North Dakota Renewable Resource Recovery Rider Accrued Refund 325 - 325 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 201 - 201 11 South Dakota Transmission Cost Recovery Rider Accrued Refund 33 - 33 11 North Dakota Generation Cost Recovery Rider Accrued Refund 28 - 28 12 Other 6 71 77 165 Total Regulatory Liabilities $ 9,804 $ 239,108 $ 248,912 Net Regulatory Asset/(Liability) Position $ 10,554 $ (96,374 ) $ (85,820 ) December 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 $ 9,090 $ 129,102 $ 138,192 see below Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment 1 - 7,772 7,772 asset lives Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 4,208 - 4,208 12 Conservation Improvement Program Costs and Incentives 2 4,024 2,844 6,868 21 MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups 1 2,033 968 3,001 24 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,681 1,681 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 715 225 940 16 Debt Reacquisition Premiums 1 201 548 749 153 Deferred Marked-to-Market Losses 1 743 - 743 12 Big Stone II Unrecovered Project Costs – South Dakota 1 144 253 397 33 Minnesota Renewable Resource Rider Accrued Revenues 2 131 - 131 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 138 245 383 34 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 122 244 366 36 Minnesota SPP Transmission Cost Recovery Tracker 1 - 202 202 see below Deferred Lease Expenses 1 - 54 54 39 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 97 - 97 2 Total Regulatory Assets $ 21,650 $ 144,138 $ 165,788 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,707 $ 141,707 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 97,726 97,726 asset lives Refundable Fuel Clause Adjustment Revenues 3,982 - 3,982 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 700 - 700 12 Prior Service Costs and Actuarial Gains on Postretirement Benefits 471 - 471 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 401 401 see below North Dakota Renewable Resource Recovery Rider Accrued Refund 1,515 - 1,515 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 164 - 164 12 North Dakota Generation Cost Recovery Rider Accrued Refund 287 - 287 6 Other 6 72 78 168 South Dakota Phase-In Rate Plan Rider Accrued Refund 355 - 355 9 Total Regulatory Liabilities $ 7,480 $ 239,906 $ 247,386 Net Regulatory Asset/(Liability) Position $ 14,170 $ (95,768 ) $ (81,598 )

Note 5 - Common Shares and Ea_2

Note 5 - Common Shares and Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Common Shares Outstanding, December 31, 2019 40,157,591 Issuances: At-the-Market Offering 112,380 Executive Stock Performance Awards (2017 awards earned) 62,497 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 30,677 Cash Invested 12,772 Vesting of Restricted Stock Units 23,000 Employee Stock Purchase Plan: Cash Invested 13,432 Dividends Reinvested 2,316 Retirements: Shares Withheld for Individual Income Tax Requirements (38,217 ) Common Shares Outstanding, March 31, 2020 40,376,448
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	2020 2019 Weighted Average Common Shares Outstanding – Basic 40,217,141 39,657,321 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 125,637 158,159 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 63,897 63,398 Nonvested Restricted Shares 19,861 21,922 Shares Expected to be Issued Under the Employee Stock Purchase Plan 15,977 - Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,823 2,365 Total Dilutive Shares 227,195 245,844 Weighted Average Common Shares Outstanding – Diluted 40,444,336 39,903,165

Note 6 - Share-based Payments (

Note 6 - Share-based Payments (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	Award Grant Date Shares/ Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Restricted Stock Units Granted: To Key Management Employees February 3, 2020 3,000 $ 54.0450 25% per year through February 6, 2024 To Executive Officers February 12, 2020 15,300 $ 54.0607 25% per year through February 6, 2024 Stock Performance Awards Granted: Under Executive Agreement February 12, 2020 47,600 $ 47.10 December 31, 2022 Under Legacy Agreement February 12, 2020 7,400 $ 52.20 December 31, 2022
Share-based Payment Arrangement, Activity [Table Text Block]	Three months ended March 31, (in thousands) 2020 2019 Stock Performance Awards Granted to Executive Officers $ 1,700 $ 1,113 Restricted Stock Dividend Equivalent Units Granted to Executive Officers and Key Employees 679 427 Restricted Stock Granted to Directors 204 165 Restricted Stock Units Granted to Non-Executive Employees 134 91 ESPP (15% discount) 53 - Totals $ 2,770 $ 1,796

Note 10 - Short-term and Long_2

Note 10 - Short-term and Long-term Borrowings (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Line of Credit Facilities [Table Text Block]	(in thousands) Line Limit In Use on March 31, 2020 Restricted due to Outstanding Letters of Credit Available on March 31, 2020 Available on December 31, 2019 Otter Tail Corporation Credit Agreement $ 170,000 $ 19,893 $ - $ 150,107 $ 164,000 OTP Credit Agreement 170,000 - 14,101 155,899 154,524 Total $ 340,000 $ 19,893 $ 14,101 $ 306,006 $ 318,524
Schedule of Debt [Table Text Block]	March 31, 20 20 (in thousands) OTP Otter Tail Corporation Consolidated Short-Term Debt $ - $ 19,893 $ 19,893 Long-Term Debt: 3.55% December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63% December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15% August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37% August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68% February 27, 2029 60,000 60,000 Senior Unsecured Notes 3.07% October 10, 2029 1 10,000 10,000 Senior Unsecured Notes 3.22% February 25, 2030 10,000 10,000 Senior Unsecured Notes 6.47% August 20, 2037 50,000 50,000 Senior Unsecured Notes 3.52% October 10, 2039 26,000 26,000 Senior Unsecured Notes 3.62% February 25, 2040 10,000 10,000 Senior Unsecured Notes 5.47% February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07% February 7, 2048 100,000 100,000 Senior Unsecured Notes 3.82% October 10, 2049 64,000 64,000 Senior Unsecured Notes 3.92% February 25, 2050 15,000 15,000 PACE Note, 2.54% March 18, 2021 306 306 Total $ 647,000 $ 80,306 $ 727,306 Less: Current Maturities net of Unamortized Debt Issuance Costs - 306 306 Unamortized Long-Term Debt Issuance Costs 2,339 343 2,682 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 644,661 $ 79,657 $ 724,318 Total Short-Term and Long-Term Debt (with current maturities) $ 644,661 $ 99,856 $ 744,517 December 31, 2019 (in thousands) Short-Term Debt $ - $ 6,000 $ 6,000 Long-Term Debt: 3.55% December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63% December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15% August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37% August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68% February 27, 2029 60,000 60,000 Senior Unsecured Notes 3.07% October 10, 2029 1 10,000 10,000 Senior Unsecured Notes 6.47% August 20, 2037 50,000 50,000 Senior Unsecured Notes 3.52% October 10, 2039 26,000 26,000 Senior Unsecured Notes 5.47% February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07% February 7, 2048 100,000 100,000 Senior Unsecured Notes 3.82% October 10, 2049 64,000 64,000 PACE Note, 2.54% March 18, 2021 351 351 Total $ 612,000 $ 80,351 $ 692,351 Less: Current Maturities net of Unamortized Debt Issuance Costs - 183 183 Unamortized Long-Term Debt Issuance Costs 2,231 356 2,587 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 609,769 $ 79,812 $ 689,581 Total Short-Term and Long-Term Debt (with current maturities) $ 609,769 $ 85,995 $ 695,764

Note 11 - Pension Plan and Ot_2

Note 11 - Pension Plan and Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 1,655 $ 1,373 Interest Cost on Projected Benefit Obligation 3,263 3,603 Expected Return on Assets (5,505 ) (5,325 ) Amortization of Prior-Service Cost: From Regulatory Asset - 1 From Other Comprehensive Income 1 - 2 Amortization of Net Actuarial Loss: From Regulatory Asset 2,231 1,163 From Other Comprehensive Income 1 55 27 Net Periodic Pension Cost 2 $ 1,699 $ 844 1 n onservice c ost c omponents of p ostretirement b enefits . 2 c osts: Service c osts included in OTP c apital e xpenditures $ 423 $ 390 Service c osts included in e lectric o peration and m aintenance e xpenses 1,192 950 Service c osts included in o ther n onelectric e xpenses 40 33 Nonservice costs capitalized as regulatory assets 11 (150 ) Nonservice costs included in n onservice cost components of postretirement benefits 33 (379 ) Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 45 $ 105 Interest Cost on Projected Benefit Obligation 362 434 Amortization of Prior Service Cost: From Regulatory Asset - 1 From Other Comprehensive Income 1 - 4 Amortization of Net Actuarial Loss: From Regulatory Asset 23 31 From Other Comprehensive Income 1 86 87 Net Periodic Pension Cost 2 $ 516 $ 662 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 Service c osts included in e lectric o peration and m aintenance e xpenses $ - $ 26 Service costs included in ot her n onelectric e xpenses 45 79 Nonservice c osts included in n onservice cost components of postretirement benefits 471 557 Three Months Ended March 31, (in thousands) 2020 2019 Service Cost—Benefit Earned During the Period $ 462 $ 321 Interest Cost on Projected Benefit Obligation 598 770 Amortization of Prior-Service Cost: From Regulatory Asset (1,169 ) - From Other Comprehensive Income 1 (29 ) - Amortization of Net Actuarial Loss: From Regulatory Asset 1,051 393 From Other Comprehensive Income 1 26 10 Net Periodic Postretirement Benefit Cost 2 $ 939 $ 1,494 Effect of Medicare Part D Subsidy $ 281 $ (45 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Service c osts included in OTP capital expenditures $ 118 $ 91 Service costs included in electric operation and maintenance expenses 333 223 Service costs included in other nonelectric expenses 11 7 Nonservice costs capitalized as regulatory assets 122 333 Nonservice costs included in n onservice cost components of postretirement benefits 355 840

Note 12 - Fair Value of Finan_2

Note 12 - Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Fair Value, by Balance Sheet Grouping [Table Text Block]	March 31, 2020 December 31, 2019 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 7,884 $ 7,884 $ 21,199 $ 21,199 Short-Term Debt (19,893 ) (19,893 ) (6,000 ) (6,000 ) Long-Term Debt including Current Maturities (724,624 ) (759,980 ) (689,764 ) (742,279 )

Note 14 - Income Tax Expense (T

Note 14 - Income Tax Expense (Tables)	3 Months Ended
	Mar. 31, 2020
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Three Months Ended March 31, (in thousands) 2020 2019 Income Before Income Taxes $ 29,906 $ 31,952 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) 7,776 8,308 Increases (Decreases) in Tax from: Differences Reversing in Excess of Federal Rates (1,229 ) (983 ) Excess Tax Deduction – Equity Method Stock Awards (402 ) (827 ) Allowance for Funds Used During Construction – Equity (312 ) (86 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) Research and Development and Other Tax Credits (54 ) (188 ) Corporate Owned Life Insurance 207 (409 ) Other Items – Net (90 ) 71 Income Tax Expense $ 5,638 $ 5,628 Effective Income Tax Rate 18.9 % 17.6 %
Summary of Income Tax Contingencies [Table Text Block]	(in thousands) 2020 2019 Balance on January 1 $ 1,488 $ 1,282 Increases Related to Tax Positions for Current Year 41 38 Uncertain Positions Resolved During Year - - Balance on March 31 $ 1,529 $ 1,320

Note 1 - Summary of Significa_3

Note 1 - Summary of Significant Accounting Policies (Details Textual) - Variable Interest Entity, Not Primary Beneficiary [Member] $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount	$ 49.6
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage	35.00%

Note 1 - Summary of Significa_4

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, 2020	Dec. 31, 2019
Fair Value, Inputs, Level 1 [Member]
Total Assets	$ 3,656	$ 3,949
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Investments	1,130	1,586
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Other Assets	2,526	2,363
Fair Value, Inputs, Level 2 [Member]
Total Assets	8,221	8,184
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Investments	2,842	2,124
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments	$ 5,379	$ 6,060

Note 1 - Summary of Significa_5

Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Finished Goods	$ 29,996	$ 31,863
Work in Process	15,811	16,508
Raw Material, Fuel and Supplies	52,345	49,480
Total Inventories	$ 98,152	$ 97,851

Note 1 - Summary of Significa_6

Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Gross Carrying Amount	$ 22,670	$ 22,670
Accumulated Amortization	11,677	11,380
Net Carrying Amount	10,993	11,290
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	11,543	11,259
Net Carrying Amount	$ 10,948	$ 11,232
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	85 months	88 months
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	185 months	188 months
Other Intangible Assets [Member]
Gross Carrying Amount	$ 179	$ 179
Accumulated Amortization	134	121
Net Carrying Amount	$ 45	$ 58
Other Intangible Assets [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	5 months	8 months
Other Intangible Assets [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	42 months	45 months

Note 1 - Summary of Significa_7

Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Amortization Expense – Intangible Assets	$ 296	$ 296

Note 1 - Summary of Significa_8

Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Mar. 31, 2020USD ($)
2020	$ 1,140
2021	1,105
2022	1,105
2023	1,104
2024	$ 1,099

Note 1 - Summary of Significa_9

Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Mar. 31, 2019
Transactions Related to Capital Additions not Settled in Cash	$ 16,193	$ 4,338

Note 1 - Summary of Signific_10

Note 1 - Summary of Significant Accounting Policies - Allowance for Credit Losses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Beginning Balance	$ 1,339	$ 1,407
Additions Charged to Expense (net of recoveries)	635	247
Reductions for Amounts Written Off	(293)	(121)
Ending Balance	$ 1,681	$ 1,533

Note 2 - Segment Information (D

Note 2 - Segment Information (Details Textual)	3 Months Ended		12 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
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			11.90%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member]
Number of Customers			5
Concentration Risk, Percentage			54.00%
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			23.80%
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			11.10%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member]
Number of Customers			2
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer One [Member]
Concentration Risk, Percentage			25.30%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer Two [Member]
Concentration Risk, Percentage			20.40%
Revenue Benchmark [Member] | UNITED STATES
Concentration Risk, Percentage	99.10%	99.00%

Note 2 - Segment Information -

Note 2 - Segment Information - Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Total Operating Revenues	$ 234,747	$ 245,972
Interest charges	8,123	7,826
Income Taxes	5,638	5,628
Net Income (Loss)	24,268	26,324
Assets	2,306,002		$ 2,273,595
Operating Segments [Member] | Electric [Member]
Regulated operating revenues	119,876	128,109
Interest charges	7,384	6,641
Income Taxes	3,620	4,771
Net Income (Loss)	16,182	18,700
Assets	1,955,465		1,931,525
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	106,690	114,955
Changes in Accrued ARP Revenues	(87)	(1,049)
Regulated operating revenues	106,603	113,906
Operating Segments [Member] | Electric [Member] | Electric Transmission [Member]
Revenue from Contracts with Customers	10,841	10,862
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	876	1,527
Operating Segments [Member] | Electric [Member] | Product and Service, Other [Member]
Revenue from Contracts with Customers	1,556	1,814
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	68,479	77,822
Interest charges	554	584
Income Taxes	1,461	1,454
Net Income (Loss)	4,927	4,842
Assets	201,892		195,742
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	57,211	66,724
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	9,883	9,045
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	1,385	2,053
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	46,397	40,058
Interest charges	148	149
Income Taxes	1,917	1,329
Net Income (Loss)	5,449	3,729
Assets	102,654		92,049
Corporate and Eliminations [Member]
Interest charges	37	452
Income Taxes	(1,360)	(1,926)
Net Income (Loss)	(2,290)	(947)
Assets	45,991		$ 54,279
Intersegment Eliminations [Member]
Regulated operating revenues	$ (5)	$ (17)

Note 3 - Rate and Regulatory _3

Note 3 - Rate and Regulatory Matters (Details Textual)	May 01, 2020USD ($)	Nov. 21, 2019	Jul. 16, 2019USD ($)	Jul. 09, 2019USD ($)	Jun. 11, 2019USD ($)	May 30, 2019USD ($)	Sep. 26, 2018USD ($)	Apr. 20, 2018USD ($)	Mar. 23, 2018USD ($)	Nov. 16, 2016USD ($)	Sep. 28, 2016	Feb. 12, 2015	Jan. 05, 2015	Nov. 06, 2014	Nov. 12, 2013	Apr. 30, 2019USD ($)	Jun. 30, 2016	Dec. 22, 2015	Mar. 31, 2020USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Nov. 02, 2017USD ($)	May 01, 2017
Federal Energy Regulatory Commission [Member]
Additional Refund from Reducing ROE																			$ 200,000
Otter Tail Power Company [Member] | Litigation Case with Minnesota Customers [Member]
Loss Contingency, Estimate of Possible Loss																					$ 2,600,000
Otter Tail Power Company [Member] | Subsequent Event [Member]
EstimatedRecovery from MNCIP	$ 2,700,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																							7.5056%
Percentage of Allowed Rate of Return on Equity																							9.41%
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member]
General Rate Revenue Increase Requested																						$ 13,100,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 4,600,000		$ 7,100,000
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%
Refunds of Excess Revenues Collected, Amounts Collected Under Higher Interim Tax Rates																$ 800,000
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2018 General Rate Case [Member]
Percentage of Allowed Rate of Return on Equity						8.75%
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
Annual Revenue Increase Approved						$ 2,200,000
Annual Revenue Requirement Shortfall Resulted from Understatement				$ 341,000
Authorized Return of Equity				8.75%
Percentage of Excess Weather-normalized Revenue, Refund to Customer				50.00%
Maximum ROE, Input for Refund to Customer				9.50%
Percentage of Any Earnings Above Maximum ROE				100.00%
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Current Return on Equity Used in Transmission Rates											10.32%				12.38%			10.32%
Proposed Reduced Return on Equity Used in Transmission Rates											9.88%	8.67%			9.15%		9.70%
Additional Incentive Basis Point														0.50%
Expected Percentage of Return on Equity											10.82%
Contract with Customer, Refund Liability, Total																			3,000,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | First Complaint Period [member]
Current Return on Equity Used in Transmission Rates											10.82%										10.38%
Additional Incentive Basis Point													0.50%
Contract with Customer, Refund Liability, Total																			1,300,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | Second Complaint Period [Member]
Current Return on Equity Used in Transmission Rates		9.88%									12.38%
Additional Incentive Basis Point													0.50%
Contract with Customer, Refund Liability, Total																			1,500,000
Otter Tail Power Company [Member] | Astoria Station Project [Member]
Current Project Capitalized Cost																			$ 78,000,000
Expanded Capacity of Projects (MW)																			245
Otter Tail Power Company [Member] | EDF [Member] | Merricourt Project [Member]
Asset Purchase Agreement, Purchase Price			$ 37,700,000		$ 37,700,000					$ 34,700,000
Turnkey Engineering, Procurement and Construction Services Agreement, Costs										$ 200,500,000
Current Project Capitalized Cost																			$ 95,800,000

Note 3 - Rate and Regulatory _4

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, 2020	Mar. 31, 2019
Revenues recorded under rate riders	$ 10,166	$ 6,880
Renewable Resource Adjustment [Member] | Minnesota1 [Member]
Revenues recorded under rate riders	3,254	1,316
Renewable Resource Adjustment [Member] | North Dakota 1 [Member]
Revenues recorded under rate riders	1,129	729
Conservation Improvement Program Costs and Incentives [Member] | Minnesota1 [Member]
Revenues recorded under rate riders	1,086	887
Conservation Improvement Program Costs and Incentives [Member] | South Dakota 1 [Member]
Revenues recorded under rate riders	344	244
Transmission Cost Recovery Rider [Member] | Minnesota1 [Member]
Revenues recorded under rate riders	715	641
Transmission Cost Recovery Rider [Member] | North Dakota 1 [Member]
Revenues recorded under rate riders	1,482	1,772
Transmission Cost Recovery Rider [Member] | South Dakota 1 [Member]
Revenues recorded under rate riders	562	473
Environmental Cost Recovery Rider [Member] | Minnesota1 [Member]
Revenues recorded under rate riders	0	(1)
Environmental Cost Recovery Rider [Member] | North Dakota 1 [Member]
Revenues recorded under rate riders	0	575
Environmental Cost Recovery Rider [Member] | South Dakota 1 [Member]
Revenues recorded under rate riders	0	(4)
Generation Cost Recovery [Member] | North Dakota 1 [Member]
Revenues recorded under rate riders	948	248
Phase-In Rate Plan [Member] | South Dakota 1 [Member]
Revenues recorded under rate riders	$ 646	$ 0

Note 3 - Rate and Regulatory _5

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]	3 Months Ended
	Mar. 31, 2020USD ($)kWh	Mar. 31, 2019USD ($)
Annual Revenue	$ 10,166,000	$ 6,880,000
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	$ 1,086,000	887,000
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2019 Incentive and Cost Recovery [Member]
Request date	May 1, 2020
Effective Date Requested or Approved	Oct. 1, 2020
Annual Revenue	$ 8,247,000
Rate rider rate (Kilowatt-Hour) | kWh	0.00485
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Jan. 1, 2020
Annual Revenue	$ 11,926,000
Rate rider rate (Kilowatt-Hour) | kWh	0.00710
Approval date	Dec. 27, 2019
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Nov. 1, 2018
Annual Revenue	$ 10,283,000
Rate rider rate (Kilowatt-Hour) | kWh	0.00600
Approval date	Oct. 4, 2018
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	$ 715,000	641,000
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member]
Request date	Nov. 30, 2018
Effective Date Requested or Approved	Jun. 1, 2019
Annual Revenue	$ 6,475,000
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario B [Member]
Annual Revenue	$ 2,708,000
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Nov. 1, 2017
Annual Revenue	$ (3,311,000)
Approval date	Oct. 30, 2017
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	$ 0	(1,000)
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved	Dec. 1, 2018
Annual Revenue	$ 0
Approval date	Nov. 29, 2018
Minnesota1 [Member] | Renewable Resource Adjustment [Member]
Annual Revenue	$ 3,254,000	1,316,000
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved	Nov. 1, 2018
Annual Revenue	$ 5,886
Rate rider rate (Kilowatt-Hour) | kWh	0.00219
Approval date	Aug. 29, 2018
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update - Revised [Member]
Effective Date Requested or Approved	Jan. 1, 2020
Annual Revenue	$ 12,506,000
Rate rider rate (Kilowatt-Hour) | kWh	0.00467
Approval date	Dec. 19, 2019
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	$ 1,482,000	1,772,000
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved	Jan. 1, 2020
Annual Revenue	$ 5,739,000
Approval date	Dec. 18, 2019
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,469,000
Approval date	Feb. 27, 2018
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member]
Effective Date Requested or Approved	Feb. 1, 2019
Annual Revenue	$ 4,801,000
Approval date	Dec. 6, 2018
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	$ 0	575,000
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved	Feb. 1, 2019
Annual Revenue	$ (378,000)
Approval date	Dec. 19, 2018
Rate of base	(0.31%)
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved	Nov. 1, 2019
Annual Revenue	$ 0
Approval date	Oct. 22, 2019
Rate of base	0.00%
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,718,000
Approval date	Feb. 27, 2018
Rate of base	5.593%
North Dakota 1 [Member] | Renewable Resource Adjustment [Member]
Annual Revenue	$ 1,129,000	729,000
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2020 Annual Update [Member]
Effective Date Requested or Approved	Apr. 1, 2020
Annual Revenue	$ 5,762,000
Approval date	Mar. 18, 2020
Rate of base	5.637%
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved	Jun. 1, 2019
Annual Revenue	$ (235,000)
Approval date	May 1, 2019
Rate of base	(0.224%)
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 9,650,000
Approval date	Feb. 27, 2018
Rate of base	7.493%
North Dakota 1 [Member] | Generation Cost Recovery [Member]
Annual Revenue	$ 948,000	248,000
North Dakota 1 [Member] | Generation Cost Recovery [Member] | The 2020 Annual Update [Member]
Request date	Mar. 2, 2020
Effective Date Requested or Approved	Jul. 1, 2020
Annual Revenue	$ 6,184,000
Rate of base	6.041%
North Dakota 1 [Member] | Generation Cost Recovery [Member] | The 2019 Initial Request [Member]
Effective Date Requested or Approved	Jul. 1, 2019
Annual Revenue	$ 2,720,000
Approval date	May 15, 2019
Rate of base	2.547%
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	$ 344,000	244,000
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	$ 562,000	473,000
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2020 Annual Update [Member]
Effective Date Requested or Approved	Mar. 1, 2020
Annual Revenue	$ 2,327,000
Approval date	Feb. 19, 2020
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved	Mar. 1, 2019
Annual Revenue	$ 1,638,000
Approval date	Feb. 20, 2019
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Rate Reset [Member]
Effective Date Requested or Approved	Oct. 1, 2019
Annual Revenue	$ 2,046,000
Approval date	Sep. 17, 2019
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved	Oct. 18, 2018
Annual Revenue	$ 1,171,000
Approval date	Oct. 18, 2018
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	$ 0	(4,000)
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved	Oct. 18, 2018
Annual Revenue	$ (189,000)
Rate rider rate (Kilowatt-Hour) | kWh	(0.00075)
Approval date	Oct. 18, 2018
South Dakota 1 [Member] | Phase-In Rate Plan [Member]
Annual Revenue	$ 646,000	$ 0
South Dakota 1 [Member] | Phase-In Rate Plan [Member] | The 2019 Initial Request [Member]
Effective Date Requested or Approved	Sep. 1, 2019
Annual Revenue	$ 864,000
Approval date	Aug. 21, 2019
Rate of base	3.345%

Note 4 - Regulatory Assets an_3

Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheets (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
		Mar. 31, 2020	Dec. 31, 2019
Regulatory Assets - Current		$ 20,358	$ 21,650
Regulatory Assets - Long -Term		142,734	144,138
Regulatory Assets - Total		163,092	165,788
Regulatory Liabilities - Current		9,804	7,480
Regulatory Liabilities - Long -Term		239,108	239,906
Regulatory Liabilities - Total		248,912	247,386
Net Regulatory Asset Position - Current		10,554	14,170
Net Regulatory Asset Position - Long-Term		(96,374)	(95,768)
Net Regulatory Asset/(Liability) Position		(85,820)	(81,598)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current		0	0
Regulatory Liabilities - Long -Term		140,112	141,707
Regulatory Liabilities - Total		140,112	141,707
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current		0	0
Regulatory Liabilities - Long -Term		98,465	97,726
Regulatory Liabilities - Total		98,465	97,726
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current		8,078	3,982
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 8,078	$ 3,982
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 662	$ 700
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 662	$ 700
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months	12 months
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Liabilities - Current		$ 471	$ 471
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 471	$ 471
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months	12 months
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current		$ 0	$ 0
Regulatory Liabilities - Long -Term		460	401
Regulatory Liabilities - Total		460	401
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		325	1,515
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 325	$ 1,515
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months	12 months
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 201	$ 164
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 201	$ 164
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		11 months	12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 33
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities - Total		$ 33
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		11 months
North Dakota Generation Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 28	$ 287
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities - Total		$ 28	$ 287
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months	6 months
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 6
Regulatory Liabilities - Long -Term		71	72
Regulatory Liabilities - Total		$ 77	$ 78
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		165 months	168 months
South Dakota Phase-in Rate Plan Rider Accrued Refund [Member]
Regulatory Liabilities - Current			$ 355
Regulatory Liabilities - Long -Term			0
Regulatory Liabilities - Total			$ 355
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			9 months
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 9,018	$ 9,090
Regulatory Assets - Long -Term	[1]	127,038	129,102
Regulatory Assets - Total	[1]	136,056	138,192
Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]	0	0
Regulatory Assets - Long -Term	[1]	8,007	7,772
Regulatory Assets - Total	[2]	8,007	7,772
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	5,965	4,208
Regulatory Assets - Long -Term	[2]	0	0
Regulatory Assets - Total	[2]	$ 5,965	$ 4,208
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	12 months	12 months
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 1,288	$ 4,024
Regulatory Assets - Long -Term	[2]	3,511	2,844
Regulatory Assets - Total	[2]	$ 4,799	$ 6,868
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	18 months	21 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]	$ 1,767	$ 2,033
Regulatory Assets - Long -Term	[1]	928	968
Regulatory Assets - Total	[1]	$ 2,695	$ 3,001
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	21 months	24 months
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member]
Regulatory Assets - Current	[1]	$ 0	$ 0
Regulatory Assets - Long -Term	[1]	1,826	1,681
Regulatory Assets - Total	[1]	1,826	1,681
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	724	715
Regulatory Assets - Long -Term	[1]	38	225
Regulatory Assets - Total	[1]	$ 762	$ 940
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	13 months	16 months
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 204	$ 201
Regulatory Assets - Long -Term	[1]	482	548
Regulatory Assets - Total	[1]	$ 686	$ 749
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	150 months	153 months
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 557	$ 743
Regulatory Assets - Total	[1]	$ 557	$ 743
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	9 months	12 months
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 144	$ 144
Regulatory Assets - Long -Term	[1]	217	253
Regulatory Assets - Total	[1]	$ 361	$ 397
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	30 months	33 months
Minnesota Renewable Resource Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 354	$ 131
Regulatory Assets - Long -Term	[2]	0	0
Regulatory Assets - Total	[2]	$ 354	$ 131
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	12 months	12 months
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 138	$ 138
Regulatory Assets - Long -Term	[1]	211	245
Regulatory Assets - Total	[1]	$ 349	$ 383
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	31 months	34 months
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 122	$ 122
Regulatory Assets - Long -Term	[1]	213	244
Regulatory Assets - Total	[1]	$ 335	$ 366
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	33 months	36 months
Minnesota SPP Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]	$ 0	$ 0
Regulatory Assets - Long -Term	[1]	206	202
Regulatory Assets - Total	[1]	206	202
South Dakota Phase-in Rate Plan Rider Accrued Refund [Member]
Regulatory Assets - Current	[2]	73
Regulatory Assets - Long -Term	[2]	0
Regulatory Assets - Total	[2]	$ 73
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	12 months
Deferred Lease Expenses [Member]
Regulatory Assets - Current	[1]	$ 0	0
Regulatory Assets - Long -Term	[1]	57	54
Regulatory Assets - Total	[1]	$ 57	$ 54
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	36 months	39 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 4	$ 4
Regulatory Assets - Long -Term	[2]	0	0
Regulatory Assets - Total	[2]	$ 4	$ 4
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	12 months	12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 97
Regulatory Assets - Long -Term	[2]		0
Regulatory Assets - Total	[2]		$ 97
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		2 months
[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.

Note 5 - Common Shares and Ea_3

Note 5 - Common Shares and Earnings Per Share (Details Textual) - Distribution Agreement With KeyBanc [Member]	Nov. 08, 2019USD ($)
Sale of Stock, Maximum Aggregate Sales Price	$ 75,000,000
Sale of Stock, Commission Percent	2.00%

Note 5 - Common Shares and Ea_4

Note 5 - Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	3 Months Ended
	Mar. 31, 2020shares
Common Shares Outstanding, beginning balance (in shares)	40,157,591
Dividends Reinvested (in shares)	30,677
Cash Invested (in shares)	12,772
Vesting of Restricted Stock Units (in shares)	23,000
Cash Invested (in shares)	13,432
Dividends Reinvested (in shares)	2,316
Shares Withheld for Individual Income Tax Requirements (in shares)	(38,217)
Common Shares Outstanding, ending balance (in shares)	40,376,448
Performance Awards 2016 [Member]
Executive Stock Performance Awards (2017 awards earned) (in shares)	62,497
At the Market Offering [Member]
At-the-Market Offering (in shares)	112,380

Note 5 - Common Shares and Ea_5

Note 5 - Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Weighted Average Common Shares Outstanding – Basic (in shares)	40,217,141	39,657,321
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares)	125,637	158,159
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	63,897	63,398
Nonvested Restricted Shares (in shares)	19,861	21,922
Shares Expected to be Issued Under the Employee Stock Purchase Plan (in shares)	15,977	0
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	1,823	2,365
Total Dilutive Shares (in shares)	227,195	245,844
Weighted Average Common Shares Outstanding – Diluted (in shares)	40,444,336	39,903,165

Note 6 - Share-based Payments_2

Note 6 - Share-based Payments (Details Textual) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)shares
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $	$ 4.3
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition (Year)	2 years 1 month 6 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 (in shares)	55,000
Period Specified for Average Adjusted Return (Year)	3 years
Number of Trading Days (Day)	20 days
Number of Shares Authorized for Actual Payment (in shares)	82,500
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 (in shares)	27,500
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 (in shares)	27,500

Note 6 - Share-based Payments -

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details)	3 Months Ended
	Mar. 31, 2020$ / sharesshares
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | February 3, 2020 [Member] | Management [Member]
Shares/units granted (in shares) | shares	3,000
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 54.0450
Shares/units granted, vesting date	25% per year through February 6, 2024
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | February 12, 2020 [Member] | Executive Officer [Member]
Shares/units granted (in shares) | shares	15,300
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 54.0607
Shares/units granted, vesting date	25% per year through February 6, 2024
Performance Shares [Member] | The 2014 Stock Incentive Plan [Member] | February 12, 2020 [Member]
Shares/units granted (in shares) | shares	47,600
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 47.10
Shares/units granted, vesting date	December 31, 2022
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member] | February 12, 2020 [Member]
Shares/units granted (in shares) | shares	7,400
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 52.20
Shares/units granted, vesting date	December 31, 2022

Note 6 - Share-based Payments_3

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals) - The 2014 Stock Incentive Plan [Member] - Restricted Stock Units (RSUs) [Member]	3 Months Ended
	Mar. 31, 2020
Management [Member] | February 3, 2020 [Member]
Shares/units granted, vesting percentage	25.00%
Executive Officer [Member] | February 12, 2020 [Member]
Shares/units granted, vesting percentage	25.00%

Note 6 - Share-based Payments_4

Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Stock compensation expense	$ 2,770	$ 1,796
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	1,700	1,113
Restricted Stock Units (RSUs) [Member] | Executive Officers and Key Employees [Member]
Stock compensation expense	679	427
Restricted Stock Units (RSUs) [Member] | Non-executive Employees [Member]
Stock compensation expense	134	91
Restricted Stock [Member] | Director [Member]
Stock compensation expense	204	165
Employee Stock Purchase Plan [Member]
Stock compensation expense	$ 53	$ 0

Note 7 - Retained Earnings an_2

Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($)	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Capitalization, Long-term Debt and Equity, Total	$ 1,524,337,000	$ 1,471,063,000
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio	50.90%
Net Assets Restricted from Distribution	$ 549,000,000
Capitalization, Long-term Debt and Equity, Total	$ 1,331,302,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Minimum [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	46.00%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	56.20%

Note 9 - Commitments and Cont_2

Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	Oct. 01, 2019	Aug. 30, 2019	Mar. 31, 2020	Dec. 31, 2019
Otter Tail Power Company [Member]
Estimated Maximum Potential Asset Impairment Charge		$ 1.1
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation			$ 3
Otter Tail Power Company [Member] | Construction Programs [Member]
Contract Expiration Year			2021	2021
Long-term Purchase Commitment, Amount			$ 250	$ 317
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			$ 10.1
T.O Plastics [Member] | Supply Agreement [Member]
Long-term Purchase Commitment, Amount	$ 1.9
Long-term Purchase Commitment, Period (Year)	6 years

Note 10 - Short-term and Long_3

Note 10 - Short-term and Long-term Borrowings (Details Textual) - Otter Tail Power Company [Member] - USD ($)	Feb. 25, 2020	Mar. 31, 2020	Sep. 12, 2019
The 2019 Note Purchase Agreement [Member]
Proceeds from Issuance of Debt	$ 35,000,000
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount		10.00%
Debt Instrument, Redemption Price, Percentage		100.00%
Interest-bearing Debt, Maximum Percentage of Total Capitalization		60.00%
Priority Debt to Total Capitalization		20.00%
The 2019 Note Purchase Agreement [Member] | Senior Unsecured Note [Member[
Debt Instrument, Face Amount			$ 175,000,000
Series 2019 A Senior Unsecured Note Due October 10, 2029 [Member]
Debt Instrument, Face Amount			$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.07%
Series 2019 B Senior Unsecured Note Due October 10, 2039 [Member]
Debt Instrument, Face Amount			$ 26,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.52%
Series 2019 C Senior Unsecured Note Due October 10, 2049 [Member]
Debt Instrument, Face Amount			$ 64,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.82%
Series 2020 A Senior Unsecured Notes Due February 25, 2030 [Member]
Debt Instrument, Face Amount			$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.22%
Series 2020 B Senior Unsecured Notes Due August 20, 2030 [Member]
Debt Instrument, Face Amount			$ 40,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.22%
Series 2020 C Senior Unsecured Notes Due February 25, 2040 [Member]
Debt Instrument, Face Amount			$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.62%
Series 2020 D Senior Unsecured Notes Due February 25, 2050 [Member]
Debt Instrument, Face Amount			$ 15,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.92%

Note 10 - Short-term and Long_4

Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Line Limit	$ 340,000
In Use	19,893
Restricted due to Outstanding Letters of Credit	14,101
Available	306,006	$ 318,524
Otter Tail Corporation Credit Agreement [Member]
Line Limit	170,000
In Use	19,893
Restricted due to Outstanding Letters of Credit	0
Available	150,107	164,000
OTP Credit Agreement [Member]
Line Limit	170,000
In Use	0
Restricted due to Outstanding Letters of Credit	14,101
Available	$ 155,899	$ 154,524

Note 10 - Short-term and Long_5

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, 2020	Dec. 31, 2019
Short-Term Debt		$ 19,893	$ 6,000
Long-Term Debt		727,306	692,351
Less: Current Maturities net of Unamortized Debt Issuance Costs		306	183
Unamortized Long-Term Debt Issuance Costs		2,682	2,587
Total Long-Term Debt net of Unamortized Debt Issuance Costs		724,318	689,581
Total Short-Term and Long-Term Debt (with current maturities)		744,517	695,764
Short-Term Debt		19,893	6,000
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt		80,000	80,000
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 [Member]
Long-Term Debt		140,000	140,000
Senior Unsecured Notes 6.15%, Series 2007B, 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 2013A, due February 27, 2029 [Member]
Long-Term Debt		60,000	60,000
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 [Member]
Long-Term Debt	[1]	10,000	10,000
Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 [Member]
Long-Term Debt		10,000
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 [Member]
Long-Term Debt		50,000	50,000
Senior Unsecured Notes 3.52%, Series 2019B, Due October 10, 2039 [Member]
Long-Term Debt		26,000	26,000
Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 [Member]
Long-Term Debt		10,000
Senior Unsecured Notes 5.47%, Series 2013B, 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
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 [Member]
Long-Term Debt		64,000	64,000
Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 [Member]
Long-Term Debt		15,000
PACE Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt		306	351
Parent Company [Member]
Short-Term Debt		19,893	6,000
Long-Term Debt		80,306	80,351
Less: Current Maturities net of Unamortized Debt Issuance Costs		306	183
Unamortized Long-Term Debt Issuance Costs		343	356
Total Long-Term Debt net of Unamortized Debt Issuance Costs		79,657	79,812
Total Short-Term and Long-Term Debt (with current maturities)		99,856	85,995
Short-Term Debt		19,893	6,000
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt		80,000	80,000
Parent Company [Member] | PACE Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt		306	351
Otter Tail Power Company [Member]
Long-Term Debt		647,000	612,000
Unamortized Long-Term Debt Issuance Costs		2,339	2,231
Total Long-Term Debt net of Unamortized Debt Issuance Costs		644,661	609,769
Total Short-Term and Long-Term Debt (with current maturities)		644,661	609,769
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 [Member]
Long-Term Debt		140,000	140,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series 2007B, 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 2013A, due February 27, 2029 [Member]
Long-Term Debt		60,000	60,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 [Member]
Long-Term Debt	[1]	10,000	10,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 [Member]
Long-Term Debt		10,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 [Member]
Long-Term Debt		50,000	50,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.52%, Series 2019B, Due October 10, 2039 [Member]
Long-Term Debt		26,000	26,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 [Member]
Long-Term Debt		10,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series 2013B, 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] | Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 [Member]
Long-Term Debt		64,000	$ 64,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 [Member]
Long-Term Debt		$ 15,000
[1]	Holder is COBANK, a cooperative lender. Interest payments are subject to cash credits which may result in a lower effective interest rate.

Note 10 - Short-term and Long_6

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, 2020	Dec. 31, 2019
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.07%	3.07%
Long-Term Debt, Due Date	Oct. 10, 2029	Oct. 10, 2029
Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.22%
Long-Term Debt, Due Date	Feb. 25, 2030
Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 3.52%, Series 2019B, Due October 10, 2039 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.52%	3.52%
Long-Term Debt, Due Date	Oct. 10, 2039	Oct. 10, 2039
Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.62%
Long-Term Debt, Due Date	Feb. 25, 2040
Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.07%	4.07%
Long-Term Debt, Due Date	Feb. 7, 2048	Feb. 7, 2048
Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.82%	3.82%
Long-Term Debt, Due Date	Oct. 10, 2049	Oct. 10, 2049
Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.92%
Long-Term Debt, Due Date	Feb. 25, 2050
PACE Note, 2.54%, due March 18, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Parent Company [Member] | PACE Note, 2.54%, due March 18, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Series 2011A, due December 1, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series 2007B, due August 20, 2022 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series 2013A, due February 27, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.07%, Series 2019A, due October 10, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.07%	3.07%
Long-Term Debt, Due Date	Oct. 10, 2029	Oct. 10, 2029
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.22%, Series 2020A, due February 25, 2030 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.22%
Long-Term Debt, Due Date	Feb. 25, 2030
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series 2007D, due August 20, 2037 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.52%, Series 2019B, Due October 10, 2039 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.52%	3.52%
Long-Term Debt, Due Date	Oct. 10, 2039	Oct. 10, 2039
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.62%. Series 2020C, due February 25, 2040 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.62%
Long-Term Debt, Due Date	Feb. 25, 2040
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series 2013B, due February 27, 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.07%	4.07%
Long-Term Debt, Due Date	Feb. 7, 2048	Feb. 7, 2048
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.82%, Series 2019C, due October 10, 2049 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.82%	3.82%
Long-Term Debt, Due Date	Oct. 10, 2049	Oct. 10, 2049
Otter Tail Power Company [Member] | Senior Unsecured Notes 3.92%, Series 2020D, due February 25, 2050 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.92%
Long-Term Debt, Due Date	Feb. 25, 2050

Note 11 - Pension Plan and Ot_3

Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual) $ in Millions	1 Months Ended
	Jan. 31, 2020USD ($)
Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 11.2

Note 11 - Pension Plan and Ot_4

Note 11 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2020	Mar. 31, 2019
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,655	$ 1,373
Interest Cost on Projected Benefit Obligation		3,263	3,603
Expected Return on Assets		(5,505)	(5,325)
From Regulatory Asset		0	1
From Other Comprehensive Income	[1]	0	2
From Regulatory Asset		2,231	1,163
From Other Comprehensive Income	[1]	55	27
Net Periodic Pension Cost	[2]	1,699	844
From Other Comprehensive Income	[1]	55	27
From Regulatory Asset		(2,231)	(1,163)
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		1,192	950
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		423	390
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		40	33
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		33	(379)
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		11	(150)
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		45	105
Interest Cost on Projected Benefit Obligation		362	434
From Regulatory Asset		0	1
From Other Comprehensive Income	[3]	0	4
From Regulatory Asset		23	31
From Other Comprehensive Income	[3]	86	87
Net Periodic Pension Cost	[4]	516	662
From Other Comprehensive Income	[3]	86	87
From Regulatory Asset		(23)	(31)
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		0	26
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		45	79
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		471	557
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		462	321
Interest Cost on Projected Benefit Obligation		598	770
From Regulatory Asset		(1,169)	0
From Other Comprehensive Income	[1]	(29)	0
From Regulatory Asset		(1,051)	(393)
From Other Comprehensive Income	[1]	26	10
Net Periodic Pension Cost	[5]	939	1,494
From Other Comprehensive Income	[1]	26	10
From Regulatory Asset		1,051	393
Effect of Medicare Part D Subsidy		281	(45)
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		333	223
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		118	91
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		11	7
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		355	840
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		$ 122	$ 333
[1]	Corporate cost included in nonservice cost components of postretirement benefits.
[2]	Allocation of costs: Service costs included in OTP capital expenditures $ 423 $ 390 Service costs included in electric operation and maintenance expenses 1,192 950 Service costs included in other nonelectric expenses 40 33 Nonservice costs capitalized as regulatory assets 11 (150 ) Nonservice costs included in nonservice cost components of postretirement benefits 33 (379 )
[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 Service costs included in other nonelectric expenses 45 79 Nonservice costs included in nonservice cost components of postretirement benefits 471 557
[5]	Allocation of Costs: Service costs included in OTP capital expenditures $ 118 $ 91 Service costs included in electric operation and maintenance expenses 333 223 Service costs included in other nonelectric expenses 11 7 Nonservice costs capitalized as regulatory assets 122 333 Nonservice costs included in nonservice cost components of postretirement benefits 355 840

Note 12 - Fair Value of Finan_3

Note 12 - Fair Value of Financial Instruments (Details Textual)	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Otter Tail Corporation Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument, Basis Spread on Variable Rate	1.50%	1.50%

Note 12 - Fair Value of Finan_4

Note 12 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2020	Dec. 31, 2019
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 7,884	$ 21,199
Short-Term Debt	(19,893)	(6,000)
Long-Term Debt including Current Maturities	(724,624)	(689,764)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	7,884	21,199
Short-Term Debt	(19,893)	(6,000)
Long-Term Debt including Current Maturities	$ (759,980)	$ (742,279)

Note 14 - Income Tax Expense (D

Note 14 - Income Tax Expense (Details Textual) - USD ($)	May 01, 2020	Mar. 31, 2020
Decrease in Unrecognized Tax Benefits is Reasonably Possible		$ 725,000
Domestic Tax Authority [Member] | Subsequent Event [Member]
Open Tax Year	2016 2017 2018 2019
State and Local Jurisdiction [Member] | Subsequent Event [Member] | North Dakota Department of Revenue [Member]
Open Tax Year	2016 2017 2018 2019
State and Local Jurisdiction [Member] | Subsequent Event [Member] | Minnesota Department of Revenue [Member]
Open Tax Year	2016 2017 2018 2019

Note 14 - Income Taxes - Effect

Note 14 - Income Taxes - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Income Before Income Taxes	$ 29,906	$ 31,952
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	7,776	8,308
Increases (Decreases) in Tax from:
Differences Reversing in Excess of Federal Rates	(1,229)	(983)
Excess Tax Deduction – Equity Method Stock Awards	(402)	(827)
Allowance for Funds Used During Construction – Equity	(312)	(86)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(258)
Research and Development and Other Tax Credits	(54)	(188)
Corporate Owned Life Insurance	207	(409)
Other Items – Net	(90)	71
Income Tax Expense	$ 5,638	$ 5,628
Effective Income Tax Rate	18.90%	17.60%

Note 14 - Income Taxs - Unrecog

Note 14 - Income Taxs - Unrecognized Tax Benefit Activity (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Balance, beginning	$ 1,488	$ 1,282
Increases Related to Tax Positions for Current Year	41	38
Uncertain Positions Resolved During Year	0	0
Balance, ending	$ 1,529	$ 1,320