Otter Tail (OTTR) 10-Q 8 Nov 19 2019 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2019	Oct. 31, 2019
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	Q3
Document Fiscal Year Focus	2019
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
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		39,759,054

Consolidated Balance Sheets (Cu

Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and Cash Equivalents	$ 921	$ 861
Accounts Receivable:
Trade—Net	92,189	75,144
Other	8,884	9,741
Inventories	97,052	106,270
Unbilled Receivables	19,020	23,626
Income Taxes Receivable	0	2,439
Regulatory Assets	12,667	17,225
Other	6,926	6,114
Total Current Assets	237,659	241,420
Investments	9,743	8,961
Other Assets	38,996	35,759
Goodwill	37,572	37,572
Other Intangibles—Net	11,562	12,450
Regulatory Assets	130,551	135,257
Right of Use Assets - Operating Leases	21,953	0
Plant
Electric Plant in Service	2,189,732	2,019,721
Nonelectric Operations	238,542	228,120
Construction Work in Progress	141,839	181,626
Total Gross Plant	2,570,113	2,429,467
Less Accumulated Depreciation and Amortization	877,958	848,369
Net Plant	1,692,155	1,581,098
Total Assets	2,180,191	2,052,517
Current Liabilities
Short-Term Debt	108,997	18,599
Current Maturities of Long-Term Debt	180	172
Accounts Payable	89,360	96,291
Accrued Salaries and Wages	19,151	24,857
Accrued Federal and State Income Taxes	3,945	0
Other Accrued Taxes	13,828	17,287
Regulatory Liabilities	6,311	738
Current Operating Lease Liabilities	4,006	0
Other Accrued Liabilities	7,409	12,149
Total Current Liabilities	253,187	170,093
Pensions Benefit Liability	75,363	98,358
Other Postretirement Benefits Liability	73,668	71,561
Long-Term Operating Lease Liabilities	18,384	0
Other Noncurrent Liabilities	28,130	24,326
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	124,602	120,976
Deferred Tax Credits	18,963	19,974
Regulatory Liabilities	238,781	226,469
Other	2,593	1,895
Total Deferred Credits	384,939	369,314
Capitalization
Long-Term Debt—Net	590,015	590,002
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2019—39,755,277 Shares; 2018—39,664,884 Shares	198,776	198,324
Premium on Common Shares	346,294	344,250
Retained Earnings	215,931	190,433
Accumulated Other Comprehensive Loss	(4,496)	(4,144)
Total Common Equity	756,505	728,863
Total Capitalization	1,346,520	1,318,865
Total Liabilities and Equity	2,180,191	2,052,517
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	Sep. 30, 2019	Dec. 31, 2018
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized (in shares)	50,000,000	50,000,000
Common shares, outstanding (in shares)	39,755,277	39,664,884
Cumulative Preferred Shares [Member]
Cumulative shares, authorized (in shares)	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0
Cumulative Preference Shares [Member]
Cumulative shares, authorized (in shares)	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0

Consolidated Statements of Inco

Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Operating Revenues:
Total Operating Revenues	$ 228,652	$ 227,662	$ 703,827	$ 695,276
Operating Expenses
Production Fuel – Electric	18,331	17,129	45,547	51,723
Electric Operation and Maintenance Expenses	35,869	33,897	114,107	111,113
Cost of Products Sold (depreciation included below)	88,747	93,361	277,325	275,691
Other Nonelectric Expenses	11,665	12,547	38,404	37,690
Depreciation and Amortization	19,657	18,708	58,229	56,216
Property Taxes – Electric	3,965	4,094	11,824	11,202
Total Operating Expenses	191,397	189,400	600,184	589,294
Operating Income	37,255	38,262	103,643	105,982
Interest Charges	7,539	7,549	23,190	22,597
Nonservice Cost Components of Postretirement Benefits	1,055	1,326	3,165	4,129
Other Income	1,020	1,245	3,114	3,135
Income Before Income Taxes	29,681	30,632	80,402	82,391
Income Tax Expense	4,936	7,359	13,907	14,207
Net Income	$ 24,745	$ 23,273	$ 66,495	$ 68,184
Average Number of Common Shares Outstanding – Basic (in shares)	39,714,672	39,621,524	39,694,677	39,592,705
Average Number of Common Shares Outstanding – Diluted (in shares)	39,946,739	39,903,565	39,922,580	39,882,105
Basic Earnings Per Common Share (in dollars per share)	$ 0.62	$ 0.59	$ 1.68	$ 1.72
Diluted Earnings Per Common Share (in dollars per share)	$ 0.62	$ 0.58	$ 1.67	$ 1.71
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 115,285	$ 105,749	$ 346,291	$ 334,858
Changes in Accrued Revenues under Alternative Revenue Programs	(921)	(317)	(1,601)	(2,757)
Total Electric Revenues	114,364	105,432	344,690	332,101
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	114,288	122,230	359,137	363,175
Electricity, Purchased [Member]
Operating Expenses
Purchased Power – Electric System Use	$ 13,163	$ 9,664	$ 54,748	$ 45,659

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Net Income	$ 24,745	$ 23,273	$ 66,495	$ 68,184
Unrealized Gain (Loss) on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	(1)	4	(5)	(106)
Unrealized Gains (Losses) Arising During Period	30	(14)	187	(93)
Income Tax (Expense) Benefit	(6)	2	(38)	42
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax	23	(8)	144	(157)
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	130	232	389	692
Income Tax Expense	(34)	(60)	(101)	(180)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act	0	0	0	(531)
Pension and Postretirement Benefit Plans – net-of-tax	96	172	288	(19)
Total Other Comprehensive Income (Loss)	119	164	432	(176)
Total Comprehensive Income	$ 24,864	$ 23,437	$ 66,927	$ 68,008

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, 2017	39,557,491
Balance at Dec. 31, 2017	$ 197,787	$ 343,450	$ 161,286	$ (5,631)	$ 696,892
Common Stock Issuances, Net of Expenses (in shares)	178,601
Common Stock Issuances, Net of Expenses	$ 893				(93)
Common Stock Issuances, Net of Expenses		(986)
Net Income			68,184		68,184
Other Comprehensive Income (Loss)				(176)	(176)
Employee Stock Incentive Plan Expense		3,402			3,402
Common Dividends			(39,895)		(39,895)
Common Stock Retirements (in shares)	(71,208)
Common Stock Retirements	$ (356)	(2,656)			(3,012)
Balance (in shares) at Sep. 30, 2018	39,664,884
Balance at Sep. 30, 2018	$ 198,324	343,210	189,575	(5,807)	725,302
Balance (in shares) at Jun. 30, 2018	39,651,436
Balance at Jun. 30, 2018	$ 198,257	342,690	179,605	(5,971)	714,581
Common Stock Issuances, Net of Expenses (in shares)	25,225
Common Stock Issuances, Net of Expenses	$ 126				0
Common Stock Issuances, Net of Expenses		(126)
Net Income			23,273		23,273
Other Comprehensive Income (Loss)				164	164
Employee Stock Incentive Plan Expense		1,149			1,149
Common Dividends			(13,303)		(13,303)
Common Stock Retirements (in shares)	(11,777)
Common Stock Retirements	$ (59)	(503)			(562)
Balance (in shares) at Sep. 30, 2018	39,664,884
Balance at Sep. 30, 2018	$ 198,324	343,210	189,575	(5,807)	725,302
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)	145,617
Common Stock Issuances, Net of Expenses	$ 728				(19)
Common Stock Issuances, Net of Expenses		(747)
Net Income			66,495		66,495
Other Comprehensive Income (Loss)				432	432
Employee Stock Incentive Plan Expense		5,245			5,245
Common Dividends			(41,781)		(41,781)
Common Stock Retirements (in shares)	(55,224)
Common Stock Retirements	$ (276)	(2,454)			(2,730)
ASU 2018-02 2017 TCJA Stranded Tax Transfer			784	(784)
Balance (in shares) at Sep. 30, 2019	39,755,277
Balance at Sep. 30, 2019	$ 198,776	346,294	215,931	(4,496)	756,505
Balance (in shares) at Jun. 30, 2019	39,754,902
Balance at Jun. 30, 2019	$ 198,775	345,030	205,115	(4,615)	744,305
Common Stock Issuances, Net of Expenses (in shares)	375
Common Stock Issuances, Net of Expenses	$ 1				(36)
Common Stock Issuances, Net of Expenses		(37)
Net Income			24,745		24,745
Other Comprehensive Income (Loss)				119	119
Employee Stock Incentive Plan Expense		1,301			1,301
Common Dividends			(13,929)		(13,929)
Balance (in shares) at Sep. 30, 2019	39,755,277
Balance at Sep. 30, 2019	$ 198,776	$ 346,294	$ 215,931	$ (4,496)	$ 756,505

Consolidated Statements of Co_2

Consolidated Statements of Common Shareholders' Equity (Unaudited) (Parentheticals) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Retained Earnings [Member]
Dividends Declared Per Common Share (in dollars per share)	$ 0.35	$ 0.335	$ 1.05	$ 1.005

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash Flows from Operating Activities
Net Income	$ 66,495	$ 68,184
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization	58,229	56,216
Deferred Tax Credits	(1,011)	(1,054)
Deferred Income Taxes	3,487	7,529
Change in Deferred Debits and Other Assets	7,142	10,641
Discretionary Contribution to Pension Plan	(22,500)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	10,344	(191)
Allowance for Equity/Other Funds Used During Construction	(1,602)	(1,586)
Stock Compensation Expense—Equity Awards	5,245	3,402
Other—Net	312	(201)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(16,213)	(27,804)
Change in Inventories	9,218	(6,581)
Change in Other Current Assets	2,974	3,827
Change in Payables and Other Current Liabilities	(20,744)	5,546
Change in Interest and Income Taxes Receivable/Payable	3,773	2,932
Net Cash Provided by Operating Activities	105,149	100,860
Cash Flows from Investing Activities
Capital Expenditures	(149,695)	(74,489)
Net Proceeds from Disposal of Noncurrent Assets	4,111	1,879
Cash Used for Investments and Other Assets	(5,546)	(3,324)
Net Cash Used in Investing Activities	(151,130)	(75,934)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	383	(7)
Net Short-Term Borrowings (Repayments)	90,398	(96,882)
Payments for Retirement of Capital Stock and Common Stock Issuance Expenses	(2,765)	(3,120)
Proceeds from Issuance of Long-Term Debt	0	100,000
Short-Term and Long-Term Debt Issuance Expenses	(66)	(441)
Payments for Retirement of Long-Term Debt	(128)	(148)
Dividends Paid	(41,781)	(39,895)
Net Cash Provided by (Used in) Financing Activities	46,041	(40,493)
Net Change in Cash and Cash Equivalents	60	(15,567)
Cash and Cash Equivalents at Beginning of Period	861	16,216
Cash and Cash Equivalents at End of Period	$ 921	$ 649

Note 1 - Summary of Significant

Note 1 - Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2019
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) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, Reg ul ated 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, RRA 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 nine September 30, 2019 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 30, 2019 2018. Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not 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 September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 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 September 30, 2019 Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 not The following table indicates there were no changes to goodwill by business segment during the first nine 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059 New Accounting Standards Adopted ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 2016 02 December 15, 2018, 842 2016 02 January 1, 2019. 8 ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income 220 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2018 02 December 15, 2018, 2018 02 The Company adopted the updates in ASU 2018 02 January 1, 2019, not Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below. (in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 ) ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. 2017 04 first 2019. no no New Accounting Standards Pending Adoption ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , may 326 December 15, 2019. not ASU 201 8 - 1 5 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	9 Months Ended
	Sep. 30, 2019
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, material handling components and extruded raw material stock. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation. The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not While no single customer accounted for over 10% 2018, 2018 2018 2018 2018 2018 2018 one All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5% and 98.1% of operating revenues for the respective three September 30, 2019 2018, nine September 30, 2019 2018. 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 nine September 30, 2019 2018 September 30, 2019 December 31, 2018 Operating Revenue Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 100,345 $ 88,750 $ 303,276 $ 287,330 Changes in Accrued ARP Revenues (921 ) (317 ) (1,601 ) (2,757 ) Total Retail Sales Revenue 99,424 88,433 301,675 284,573 Transmission Services Revenue 11,692 12,569 34,023 35,785 Wholesale Revenues – Company Generation 1,631 2,826 4,099 6,380 Other Revenues 1,626 1,614 4,929 5,394 Total Electric Segment Revenues 114,373 105,442 344,726 332,132 Manufacturing Segment: Metal Parts and Tooling 56,255 55,864 185,520 170,179 Plastic Products and Tooling 8,088 8,790 26,486 26,986 Other 1,379 2,373 5,034 6,678 Total Manufacturing Segment Revenues 65,722 67,027 217,040 203,843 Plastics Segment – Sale of PVC Pipe Products 48,566 55,203 142,100 159,332 Intersegment Eliminations (9 ) (10 ) (39 ) (31 ) Total $ 228,652 $ 227,662 $ 703,827 $ 695,276 Interest Charges Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,300 $ 6,509 $ 19,566 $ 19,586 Manufacturing 561 555 1,791 1,664 Plastics 197 150 561 460 Corporate and Intersegment Eliminations 481 335 1,272 887 Total $ 7,539 $ 7,549 $ 23,190 $ 22,597 Income Taxes Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 4,066 $ 5,172 $ 9,874 $ 7,881 Manufacturing 285 799 2,888 3,040 Plastics 1,914 2,276 5,287 6,897 Corporate (1,329 ) (888 ) (4,142 ) (3,611 ) Total $ 4,936 $ 7,359 $ 13,907 $ 14,207 Net Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 17,682 $ 14,567 $ 43,884 $ 41,835 Manufacturing 3,155 3,022 11,987 10,769 Plastics 5,397 6,432 14,918 19,505 Corporate (1,489 ) (748 ) (4,294 ) (3,925 ) Total $ 24,745 $ 23,273 $ 66,495 $ 68,184 Identifiable Assets September 30, December 31, (in thousands) 2019 2018 Electric $ 1,829,271 $ 1,728,534 Manufacturing 206,835 187,556 Plastics 97,459 91,630 Corporate 46,626 44,797 Total $ 2,180,191 $ 2,052,517

Note 3 - Rate and Regulatory Ma

Note 3 - Rate and Regulatory Matters	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Public Utilities Disclosure [Text Block]	3. Below are descriptions of OTP’s major capital expenditure projects that have had, or are expected to have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2019 2018. Major Capital Expenditure Projects Astoria Station 2021. November 3, 2017, August 3, 2018 Station. In a September 26, 2018 March 6, 2019 December 2018 January 2019. May 2019. September 30, 2019, Merricourt Wind Energy Center (Merricourt) November 16, 2016 November 16, 2016, October 26, 2017 January 10, 2018. November 3, 2017. March 6, 2019 April 2019. In connection with action by the FERC, OTP and EDF agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, July 16, 2019, August 2019. September 30, 2019, Big Stone South–Ellendale Multi-Value Transmission Project (MVP) February 6, 2019, December 2011. Recovery of OTP’s major transmission investments is through the MISO Tariff and Minnesota, North Dakota and South Dakota base rates and TCR riders. Minnesota General Rates 2016 March 2017 May 1, 2017. The MPUC’s order also included: ( 1 2 November 1, 2017. Minnesota Conservation Improvement Programs (MNCIP) not May 25, 2016 2017 2018 2019 2017 2018 2019 May 20, 2019 2017 2019 one 2020.   On April 1, 2019 2018 2018 not May 31, 2019 2018 June 24, 2019 $3.0 October 24, 2019 2018. Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 March 11, 2019. On November 30, 2018 two two 2019. April 1, 2019, not September 30, 2019 Environmental Cost Recovery Rider 2010 2016 November 2017. 2018 zero December 1, 2018. March April 2019. Renewable Resource Adjustment November 1, 2017, 2017 2018. June 21, 2019 September 30, 2019 Fuel and Purchased Power Costs Recovery December 2017 July 31, 2019 twelve January 1, 2020. On implementation of the new mechanism, OTP will be required to accrue a liability and likely refund amounts of fuel and purchased power and related costs per kwh collected in excess of forecasted amounts per kwh submitted to the MPUC for setting rates for the upcoming year. OTP will continue to accrue revenue and a regulatory asset for fuel and purchased power costs incurred in excess of amounts recovered, that it expects to recover under the adjustment mechanism, unless and until recovery of those excess amounts are deemed not not North Dakota General Rates November 2, 2017 December 20, 2017 January 1, 2018. February 27, 2018 March 1, 2018. On March 23, 2018 In a September 26, 2018 March 2018 not February 1, 2019, April 2019 Renewable Resource Adjustment Effective in February 2019 2017 Transmission Cost Recovery Rider 2017 26 26A 2017 OTP filed its annual update to the North Dakota TCR rider on August 30, 2019 January 1, 2020. Environmental Cost Recovery Rider 2017 February 1, 2019, February 1, 2019 October 22, 2019 zero November 1, 2019 December 31, 2019. Generation Cost Recovery Rider March 1, 2019 May 15, 2019. July 1, 2019. South Dakota General Rates April 20, 2018 first two October 18, 2018. second The SDPUC approved a partial settlement on March 1, 2019 second January 1, 2018 October 17, 2018 first 2019. May 14, 2019. May 30, 2019 June 28, 2019 August 1, 2019. October 18, 2018 October 2019 On July 9, 2019 2018 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 30 Transmission Cost Recovery Rider January 29, 2018 October 18, 2018, 2018 OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. February 20, 2019 March 1, 2019. January 1, 2019 January 2020. OTP made a supplemental filing for the South Dakota TCR rider on September 5, 2019 2018 September 17, 2019 October 1, 2019. Environmental Cost Recovery Rider October 18, 2018 October 2019 Phase-In Rate Plan Rider May 31, 2019 OTP made a supplemental filing for the South Dakota Phase-In Rate Plan Rider on August 2, 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. Three Months Ended September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives $ 1,518 $ 1,488 $ 4,246 $ 4,300 Renewable Resource Recovery 1,316 817 3,949 2,001 Transmission Cost Recovery (284 ) (1,196 ) 301 (1,683 ) Environmental Cost Recovery - 24 (1 ) (25 ) North Dakota Transmission Cost Recovery 908 1,922 3,554 5,149 Renewable Resource Adjustment (20 ) 2,220 616 6,266 Generation Cost Recovery 137 - 607 - Environmental Cost Recovery (7 ) 1,823 556 5,474 South Dakota Transmission Cost Recovery 743 496 1,587 1,282 Conservation Improvement Program Costs and Incentives 100 238 440 589 Phase-In Rate Plan Recovery (10 ) - (10 ) - Environmental Cost Recovery (2 ) 545 (29 ) 1,580 Total $ 4,399 $ 8,377 $ 15,816 $ 24,933 Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2017 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2018 Incentive and Cost Recovery A – October 24, 2019 December 1, 2019 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536 /kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ - 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2019 Annual Update – Revised R – September 30, 2019 November 1, 2019 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $0.00049 /kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base Transmission Cost Recovery 2019 Annual Update R – August 30, 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 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 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 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base Generation Cost Recovery 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 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 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483 /kwh Phase-In Rate Plan Recovery 2019 Initial Request A – August 21, 2019 September 1, 2019 $ 864 3.345% of base TCJA The TCJA, passed in December 2017, January 1, 2018. The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. August 9, 2018 December 5, 2018 one ten 2017 June 1, 2019. one January 2018 May 2019 August September 2019. As described above, OTP’s recent general rate cases in North Dakota and South Dakota reflected the impact of the TCJA in interim rates. OTP accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurred under the lower federal tax rates in the TCJA. The North Dakota liability of $0.8 million as of March 31, 2019 January February 2018 April 2019. As of September 30, 2019, March 15, 2018, 2018 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 second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 second Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, first 15 February June 2017 2016 December 31, 2016 September 30, 2019. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second On October 16, 2018 April 2017. 206 November 15, 2018, two February 13, 2019 April 10, 2019. no September 30, 2019 second On March 1, 2019 two 2019,

Note 4 - Regulatory Assets and

Note 4 - Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 113,657 $ 120,012 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,571 7,571 asset lives Conservation Improvement Program Costs and Incentives 2 243 5,339 5,582 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,856 - 2,856 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,525 1,525 asset lives Deferred Marked-to-Market Losses 1 972 186 1,158 15 Big Stone II Unrecovered Project Costs – Minnesota 1 706 409 1,115 19 Debt Reacquisition Premiums 1 203 598 801 156 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 60 711 771 27 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 418 - 418 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 234 350 36 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 339 - 339 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 270 270 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 193 - 193 5 Recoverable Fuel and Purchased Power Costs – South Dakota 1 124 - 124 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 78 - 78 9 Deferred Lease Expenses 1 - 51 51 42 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 3 Total Regulatory Assets $ 12,667 $ 130,551 $ 143,218 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,337 $ 141,337 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 96,981 96,981 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 3,836 - 3,836 3 North Dakota Renewable Resource Recovery Rider Accrued Refund 684 - 684 8 North Dakota Transmission Cost Recovery Rider Accrued Refund 601 - 601 2 North Dakota Environmental Cost Recovery Rider Accrued Refund 537 - 537 2 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 342 342 see below Refundable Fuel Clause Adjustment Revenues – North Dakota 305 - 305 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 140 47 187 15 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 151 - 151 12 South Dakota Phase-In Rate Plan Rider Accrued Refund 39 - 39 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 12 - 12 12 Other 6 74 80 171 Total Regulatory Liabilities $ 6,311 $ 238,781 $ 245,092 Net Regulatory Asset/(Liability) Position $ 6,356 $ (108,230 ) $ (101,874 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 - 444 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 - 178 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 Deferred Income Taxes 1 - 2,423 2,423 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 - 452 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 - 328 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 - 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ - $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,229 83,229 asset lives Refundable Fuel Clause Adjustment Revenues 121 - 121 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 177 - 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 - 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up - 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 - 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 - 207 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. 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. 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. 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 – 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 156 MISO Schedule 26/26A 26/26A 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. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 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 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. North Dakota Generation Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to recovery from North Dakota customers that had not 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 regulatory asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes 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. Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to recovery from other Minnesota customers as of the balance sheet date. North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that were recoverable from North Dakota customers as of the balance sheet date. 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 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 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. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that were refundable to North Dakota customers as of the balance sheet date. Effective February 1, 2019 Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred. The 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 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. The Minnesota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that were refundable 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 South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that were refundable to South Dakota customers as of the balance sheet date.

Note 5 - Common Shares and Earn

Note 5 - Common Shares and Earnings Per Share	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Stockholders Equity and Earnings per Share [Text Block]	5. Shelf Registration On May 3, 2018 may May 3, 2021. Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2018 September 30, 2019: Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 27,125 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, September 30, 2019 39,755,277 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three nine September 30, 2019 2018. not Three Months ended September 30, Nine Months ended September 30, 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,714,672 39,621,524 39,694,677 39,592,705 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 149,023 206,268 147,106 210,691 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 68,138 58,680 63,902 58,475 Nonvested Restricted Shares 13,107 14,761 14,896 17,712 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,799 2,332 1,999 2,522 Total Dilutive Shares 232,067 282,041 227,903 289,400 Weighted Average Common Shares Outstanding – Diluted 39,946,739 39,903,565 39,922,580 39,882,105 The effect of dilutive shares on earnings per share for the three nine September 30, 2019 2018, no $0.01

Note 6 - Share-based Payments

Note 6 - Share-based Payments	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Share-based Payment Arrangement [Text Block]	6. Stock Incentive Awards The following stock incentive awards were granted under the 2014 nine September 30, 2019: Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted: Under Executive and Select Employee Agreements February 13, 2019 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement February 13, 2019 7,800 $ 45.885 December 31, 2021 Restricted Stock Units Granted to Executive Officers February 13, 2019 15,600 $ 49.6225 25% per year through February 6, 2023 Restricted Stock Units Granted to Key Employees April 8, 2019 13,270 $ 44.45 100% on April 8, 2023 Restricted Stock Granted to Nonemployee Directors April 8, 2019 15,700 $ 49.73 33% per year through April 8, 2022 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price per share on the date of grant. The grant-date fair value of each restricted stock unit granted to a key employee that is not Under the performance share awards the aggregate award for performance at target is 55,600 shares. For target performance the participants would earn an aggregate of 27,800 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,800 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2019 December 31, 2021, January 1, 2019 20 January 1, 2022. may zero no 718, Compensation – Stock Compensation Under the 2019 The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not 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. Employee Stock Purchase Plan In July 2019 15% six 718, Compensation–Stock Compensation 718 As of September 30, 2019, Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three nine September 30, 2019 2018 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 743 $ 718 $ 3,274 $ 2,037 Restricted Stock Units Granted to Executive Officers 189 174 999 596 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 203 165 572 496 Restricted Stock Units Granted to Key Employees 112 92 346 257 ESPP (15% discount) 54 - 54 - Totals $ 1,301 $ 1,149 $ 5,245 $ 3,402

Note 7 - Retained Earnings and

Note 7 - Retained Earnings and Dividend Restriction	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Retained Earnings Restrictions [Text Block]	7. and Dividend Restriction 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 September 30, 2019, 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. September 30, 2019, 2019

Note 8 - Leases

Note 8 - Leases	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Lessee, Operating Leases [Text Block]	8. The Company adopted ASU 2016 02 842 January 1, 2019, not 842 12 $20 January 1, 2019. not not The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic 840. not The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than one ten None January 1, 2019, 50 no The right-of-use asset operating leases in place at the time of adoption were capitalized on the basis of their remaining payment obligation balances, discounted to present value based on the Company’s incremental borrowing rates (IBRs) appropriate to the leased asset and lease terms. The remaining payments for operating lease right-of-use assets are being charged to expense on a straight-line basis over the life of the lease. For the Company’s current lease obligations, no no The breakdown of right-of-use assets and lease liabilities as of September 30, 2019 (in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,557 $ 19,967 $ 666 $ 769 $ 24,959 Accumulated Amortization (778 ) (1,836 ) (294 ) (98 ) (3,006 ) Net of Accumulated Amortization $ 2,779 $ 18,131 $ 372 $ 671 $ 21,953 Obligations: Current Operating Lease Liabilities $ 985 $ 2,541 $ 326 $ 154 $ 4,006 Long-Term Operating Lease Liabilities 2,081 15,686 45 572 18,384 Total Lease Liabilities $ 3,066 $ 18,227 $ 371 $ 726 $ 22,390 The amounts of the Company’s right-of-use operating lease obligations as of September 30, 2019 five 2019 2023 2023 (in thousands) Right-of-Use Operating Leases OTP Nonelectric Total 2019 $ 275 $ 1,029 $ 1,304 2020 1,115 3,883 4,998 2021 1,100 3,619 4,719 2022 206 3,491 3,697 2023 196 3,203 3,399 Beyond 2023 448 7,979 8,427 Total Minimum Obligations $ 3,340 $ 23,204 $ 26,544 Interest Component of Obligations (274 ) (3,880 ) (4,154 ) Present Value of Minimum Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 6.2 years and the weighted-average discount rate is 5.3%. A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 January 1, 2019 September 30, 2019 (in thousands) OTP Nonelectric Total Operating Lease Obligations, January 1, 2019 $ 3,609 $ 16,760 $ 20,369 Non-cash Acquisition of Right-of-Use Assets 177 5,115 5,292 Lease Modifications - (164 ) (164 ) Lease Obligation Payments (845 ) (3,086 ) (3,931 ) Interest Component of Lease Obligation Payment 125 699 824 Operating Lease Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 The lease modifications in the above table relate to reductions in future minimum lease obligations on several units of leased equipment at BTD. OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income. The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the three nine September 30, 2019 Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost Variable Lease Cost Total Lease Cost Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ - $ 9 $ 29 $ - $ 29 Inventory 244 - 244 707 - 707 Cost of Products Sold 963 65 1,028 2,942 137 3,079 Electric Operation and Maintenance Expenses 64 - 64 194 - 194 Other Nonelectric Expenses 51 (1 ) 50 156 - 156 Total $ 1,331 $ 64 $ 1,395 $ 4,028 $ 137 $ 4,165

Note 9 - Commitments and Contin

Note 9 - Commitments and Contingencies	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	9. Construction and Other Purchase Commitments At September 30, 2019 December 31, 2018 2019 2020 2021. 2019 2019 At December 31, 2018 December 31, 2021 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 2042. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2020. OTP has an agreement with Peabody COALSALES, LLC for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020. no December 31, 2023. no October 2019, two October, two seventy-five OTP Land Easements OTP has commitments to make future payments for land easements not Contingencies OTP had a $1.6 million refund liability on its balance sheet as of September 30, 2019 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, and litigation matters. In 2015 111 not 2016. 2017, April 2018. On August 21, 2018 September 6, 2019, two not 2022 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 September 30, 2019, not

Note 10 - Short-term and Long-t

Note 10 - Short-term and Long-term Borrowings	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Debt Disclosure [Text Block]	10. The following table presents the status of the Company’s lines of credit as of September 30, 2019 December 31, 2018: (in thousands) Line Limit In Use on September 30, 2019 Restricted due to Outstanding Letters of Credit Available on September 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 35,837 $ - $ 94,163 $ 120,785 OTP Credit Agreement 170,000 73,160 16,561 80,279 160,316 Total $ 300,000 $ 108,997 $ 16,561 $ 174,442 $ 281,101 On October 31, 2019 one October 31, 2023 October 31, 2024 4.2 4.3 10 The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2019 December 31, 2018: September 30, 2019 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 73,160 $ 35,837 $ 108,997 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 394 394 Total $ 512,000 $ 80,394 $ 592,394 Less: Current Maturities net of Unamortized Debt Issuance Costs - 180 180 Unamortized Long-Term Debt Issuance Costs 1,830 369 2,199 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,170 $ 79,845 $ 590,015 Total Short-Term and Long-Term Debt (with current maturities) $ 583,330 $ 115,862 $ 699,192 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs - 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773 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 October 10, 2019, 2019A 2019B 2019C 2019 2019 2020A 2020C 2020D February 25, 2020, 2020B August 20, 2020, OTP may 2019 not 2019 no 2019 2019A April 10, 2029, ( 2019B April 10, 2039 2019C April 10, 2049 2019 2019 The 2019 2019 may not 2019 2019 2019 not 2019 not 2019 2019 2019 2019 2019 no The 2019 4.1 10

Note 11 - Pension Plan and Othe

Note 11 - Pension Plan and Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Pension and Other Postretirement Benefits Disclosure [Text Block]	1 1 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 $ 4,119 $ 4,845 Interest Cost on Projected Benefit Obligation 3,603 3,363 10,809 10,089 Expected Return on Assets (5,324 ) (5,300 ) (15,973 ) (15,899 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 4 12 From Other Comprehensive Income 1 2 - 6 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 3,488 5,351 From Other Comprehensive Income 1 26 46 79 137 Net Periodic Pension Cost 2 $ 844 $ 1,512 $ 2,532 $ 4,535 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in n onservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 ) Cash flows no December 31, 2018 January 2019 September 2019. Executive Survivor and Supplemental Retirement Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 313 $ 300 Interest Cost on Projected Benefit Obligation 433 399 1,301 1,197 Amortization of Prior-Service Cost: From Regulatory Asset 2 4 4 12 From Other Comprehensive Income 1 4 10 12 29 Amortization of Net Actuarial Loss: From Regulatory Asset 31 66 93 200 From Other Comprehensive Income 1 87 166 262 496 Net Periodic Pension Cost 2 $ 661 $ 745 $ 1,985 $ 2,234 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in n onservice cost components of postretirement benefits 557 645 1,672 1,934 Other Postretirement Benefits Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 $ 964 $ 1,145 Interest Cost on Projected Benefit Obligation 770 646 2,312 1,937 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 1,178 1,236 From Other Comprehensive Income 1 10 11 29 32 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,451 $ 4,483 $ 4,350 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) $ (134 ) $ (110 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in n onservice cost components of postretirement benefits 889 768 2,614 2,436

Note 12 - Fair Value of Financi

Note 12 - Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Fair Value Disclosures [Text Block]	1 2 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt September 30, 2019 December 31, 2018 1.50% Long-Term Debt including Current Maturities 2 820. September 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 921 $ 921 $ 861 $ 861 Short-Term Debt (108,997 ) (108,997 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,195 ) (663,761 ) (590,174 ) (601,513 )

Note 13 - Property, Plant and E

Note 13 - Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Property, Plant and Equipment Disclosure [Text Block]	13. No

Note 14 - Income Tax Expense

Note 14 - Income Tax Expense	9 Months Ended
	Sep. 30, 2019
Notes to Financial Statements
Income Tax Disclosure [Text Block]	1 4 . Income Tax Expense The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three nine September 30, 2019 2018: Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 29,681 $ 30,632 $ 80,402 $ 82,391 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 7,717 $ 7,964 $ 20,905 $ 21,422 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (933 ) (838 ) (2,690 ) (2,932 ) Research and Development Tax Credits (612 ) (202 ) (987 ) (562 ) Excess Tax Deduction – Equity Method Stock Awards - (73 ) (827 ) (698 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (774 ) (774 ) Reconciliation and Prior Period Adjustments (688 ) 2,109 (722 ) 2,028 Corporate Owned Life Insurance (50 ) (332 ) (609 ) (360 ) Allowance for Funds Used During Construction – Equity (239 ) (138 ) (419 ) (416 ) Federal Production Tax Credits - (707 ) - (2,757 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (1 ) (166 ) 30 (213 ) Income Tax Expense $ 4,936 $ 7,359 $ 13,907 $ 14,207 Effective Income Tax Rate 16.6 % 24.0 % 17.3 % 17.2 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Prior Years 37 6 Increases Related to Tax Positions for Current Year 153 113 Uncertain Positions Resolved During Year (170 ) (186 ) Balance on September 30 $ 1,302 $ 617 The balance of unrecognized tax benefits as of September 30, 2019 September 30, 2019 not September 30, 2019. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2019, no 2016 2015

Significant Accounting Policies

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Revenue [Policy Text Block]	Revenue Recognition Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the 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) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, Reg ul ated 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, RRA 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 nine September 30, 2019 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 30, 2019 2018.
Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block]	Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not
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 September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 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 September 30, 2019
Inventory, Policy [Policy Text Block]	Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 not The following table indicates there were no changes to goodwill by business segment during the first nine 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099
Cash Flow Supplemental [Policy Text Block]	Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Standards Adopted ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 2016 02 December 15, 2018, 842 2016 02 January 1, 2019. 8 ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income 220 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2018 02 December 15, 2018, 2018 02 The Company adopted the updates in ASU 2018 02 January 1, 2019, not Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below. (in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 ) ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. 2017 04 first 2019. no no New Accounting Standards Pending Adoption ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , may 326 December 15, 2019. not ASU 201 8 - 1 5 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)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484
Schedule of Inventory, Current [Table Text Block]	September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270
Schedule of Goodwill [Table Text Block]	(in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572
Schedule of Finite-Lived Intangible Assets [Table Text Block]	September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	(in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	(in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 )

Note 2 - Segment Information (T

Note 2 - Segment Information (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 100,345 $ 88,750 $ 303,276 $ 287,330 Changes in Accrued ARP Revenues (921 ) (317 ) (1,601 ) (2,757 ) Total Retail Sales Revenue 99,424 88,433 301,675 284,573 Transmission Services Revenue 11,692 12,569 34,023 35,785 Wholesale Revenues – Company Generation 1,631 2,826 4,099 6,380 Other Revenues 1,626 1,614 4,929 5,394 Total Electric Segment Revenues 114,373 105,442 344,726 332,132 Manufacturing Segment: Metal Parts and Tooling 56,255 55,864 185,520 170,179 Plastic Products and Tooling 8,088 8,790 26,486 26,986 Other 1,379 2,373 5,034 6,678 Total Manufacturing Segment Revenues 65,722 67,027 217,040 203,843 Plastics Segment – Sale of PVC Pipe Products 48,566 55,203 142,100 159,332 Intersegment Eliminations (9 ) (10 ) (39 ) (31 ) Total $ 228,652 $ 227,662 $ 703,827 $ 695,276 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,300 $ 6,509 $ 19,566 $ 19,586 Manufacturing 561 555 1,791 1,664 Plastics 197 150 561 460 Corporate and Intersegment Eliminations 481 335 1,272 887 Total $ 7,539 $ 7,549 $ 23,190 $ 22,597 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 4,066 $ 5,172 $ 9,874 $ 7,881 Manufacturing 285 799 2,888 3,040 Plastics 1,914 2,276 5,287 6,897 Corporate (1,329 ) (888 ) (4,142 ) (3,611 ) Total $ 4,936 $ 7,359 $ 13,907 $ 14,207 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 17,682 $ 14,567 $ 43,884 $ 41,835 Manufacturing 3,155 3,022 11,987 10,769 Plastics 5,397 6,432 14,918 19,505 Corporate (1,489 ) (748 ) (4,294 ) (3,925 ) Total $ 24,745 $ 23,273 $ 66,495 $ 68,184 September 30, December 31, (in thousands) 2019 2018 Electric $ 1,829,271 $ 1,728,534 Manufacturing 206,835 187,556 Plastics 97,459 91,630 Corporate 46,626 44,797 Total $ 2,180,191 $ 2,052,517

Note 3 - Rate and Regulatory _2

Note 3 - Rate and Regulatory Matters (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Revenues Recorded under Rate Riders [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives $ 1,518 $ 1,488 $ 4,246 $ 4,300 Renewable Resource Recovery 1,316 817 3,949 2,001 Transmission Cost Recovery (284 ) (1,196 ) 301 (1,683 ) Environmental Cost Recovery - 24 (1 ) (25 ) North Dakota Transmission Cost Recovery 908 1,922 3,554 5,149 Renewable Resource Adjustment (20 ) 2,220 616 6,266 Generation Cost Recovery 137 - 607 - Environmental Cost Recovery (7 ) 1,823 556 5,474 South Dakota Transmission Cost Recovery 743 496 1,587 1,282 Conservation Improvement Program Costs and Incentives 100 238 440 589 Phase-In Rate Plan Recovery (10 ) - (10 ) - Environmental Cost Recovery (2 ) 545 (29 ) 1,580 Total $ 4,399 $ 8,377 $ 15,816 $ 24,933
Schedule of Information on Status of Updates for Previous Periods [Table Text Block]	Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2018 Incentive and Cost Recovery A – October 24, 2019 December 1, 2019 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536 /kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ - 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2019 Annual Update – Revised R – September 30, 2019 November 1, 2019 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $0.00049 /kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base Transmission Cost Recovery 2019 Annual Update R – August 30, 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 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 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 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base Generation Cost Recovery 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 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 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483 /kwh 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)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Regulatory Assets and Liabilities [Table Text Block]	September 30, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 113,657 $ 120,012 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,571 7,571 asset lives Conservation Improvement Program Costs and Incentives 2 243 5,339 5,582 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,856 - 2,856 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,525 1,525 asset lives Deferred Marked-to-Market Losses 1 972 186 1,158 15 Big Stone II Unrecovered Project Costs – Minnesota 1 706 409 1,115 19 Debt Reacquisition Premiums 1 203 598 801 156 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 60 711 771 27 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 418 - 418 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 234 350 36 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 339 - 339 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 270 270 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 193 - 193 5 Recoverable Fuel and Purchased Power Costs – South Dakota 1 124 - 124 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 78 - 78 9 Deferred Lease Expenses 1 - 51 51 42 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 3 Total Regulatory Assets $ 12,667 $ 130,551 $ 143,218 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,337 $ 141,337 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 96,981 96,981 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 3,836 - 3,836 3 North Dakota Renewable Resource Recovery Rider Accrued Refund 684 - 684 8 North Dakota Transmission Cost Recovery Rider Accrued Refund 601 - 601 2 North Dakota Environmental Cost Recovery Rider Accrued Refund 537 - 537 2 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 342 342 see below Refundable Fuel Clause Adjustment Revenues – North Dakota 305 - 305 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 140 47 187 15 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 151 - 151 12 South Dakota Phase-In Rate Plan Rider Accrued Refund 39 - 39 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 12 - 12 12 Other 6 74 80 171 Total Regulatory Liabilities $ 6,311 $ 238,781 $ 245,092 Net Regulatory Asset/(Liability) Position $ 6,356 $ (108,230 ) $ (101,874 ) December 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 - 444 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 - 178 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 Deferred Income Taxes 1 - 2,423 2,423 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 - 452 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 - 328 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 - 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ - $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,229 83,229 asset lives Refundable Fuel Clause Adjustment Revenues 121 - 121 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 177 - 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 - 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up - 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 - 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 - 207 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 )

Note 5 - Common Shares and Ea_2

Note 5 - Common Shares and Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 27,125 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, September 30, 2019 39,755,277
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Three Months ended September 30, Nine Months ended September 30, 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,714,672 39,621,524 39,694,677 39,592,705 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 149,023 206,268 147,106 210,691 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 68,138 58,680 63,902 58,475 Nonvested Restricted Shares 13,107 14,761 14,896 17,712 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,799 2,332 1,999 2,522 Total Dilutive Shares 232,067 282,041 227,903 289,400 Weighted Average Common Shares Outstanding – Diluted 39,946,739 39,903,565 39,922,580 39,882,105

Note 6 - Share-based Payments (

Note 6 - Share-based Payments (Tables)	9 Months Ended
	Sep. 30, 2019
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 Stock Performance Awards Granted: Under Executive and Select Employee Agreements February 13, 2019 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement February 13, 2019 7,800 $ 45.885 December 31, 2021 Restricted Stock Units Granted to Executive Officers February 13, 2019 15,600 $ 49.6225 25% per year through February 6, 2023 Restricted Stock Units Granted to Key Employees April 8, 2019 13,270 $ 44.45 100% on April 8, 2023 Restricted Stock Granted to Nonemployee Directors April 8, 2019 15,700 $ 49.73 33% per year through April 8, 2022
Share-based Payment Arrangement, Activity [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 743 $ 718 $ 3,274 $ 2,037 Restricted Stock Units Granted to Executive Officers 189 174 999 596 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 203 165 572 496 Restricted Stock Units Granted to Key Employees 112 92 346 257 ESPP (15% discount) 54 - 54 - Totals $ 1,301 $ 1,149 $ 5,245 $ 3,402

Note 8 - Leases (Tables)

Note 8 - Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Leases, Right-of-use Assets and Lease Liabilities By Business Segment [Table Text Block]	(in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,557 $ 19,967 $ 666 $ 769 $ 24,959 Accumulated Amortization (778 ) (1,836 ) (294 ) (98 ) (3,006 ) Net of Accumulated Amortization $ 2,779 $ 18,131 $ 372 $ 671 $ 21,953 Obligations: Current Operating Lease Liabilities $ 985 $ 2,541 $ 326 $ 154 $ 4,006 Long-Term Operating Lease Liabilities 2,081 15,686 45 572 18,384 Total Lease Liabilities $ 3,066 $ 18,227 $ 371 $ 726 $ 22,390
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	(in thousands) Right-of-Use Operating Leases OTP Nonelectric Total 2019 $ 275 $ 1,029 $ 1,304 2020 1,115 3,883 4,998 2021 1,100 3,619 4,719 2022 206 3,491 3,697 2023 196 3,203 3,399 Beyond 2023 448 7,979 8,427 Total Minimum Obligations $ 3,340 $ 23,204 $ 26,544 Interest Component of Obligations (274 ) (3,880 ) (4,154 ) Present Value of Minimum Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390
Lessee, Operating Lease, Lease Obligation Activity [Table Text Block]	(in thousands) OTP Nonelectric Total Operating Lease Obligations, January 1, 2019 $ 3,609 $ 16,760 $ 20,369 Non-cash Acquisition of Right-of-Use Assets 177 5,115 5,292 Lease Modifications - (164 ) (164 ) Lease Obligation Payments (845 ) (3,086 ) (3,931 ) Interest Component of Lease Obligation Payment 125 699 824 Operating Lease Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390
Lease, Cost [Table Text Block]	Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost Variable Lease Cost Total Lease Cost Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ - $ 9 $ 29 $ - $ 29 Inventory 244 - 244 707 - 707 Cost of Products Sold 963 65 1,028 2,942 137 3,079 Electric Operation and Maintenance Expenses 64 - 64 194 - 194 Other Nonelectric Expenses 51 (1 ) 50 156 - 156 Total $ 1,331 $ 64 $ 1,395 $ 4,028 $ 137 $ 4,165

Note 10 - Short-term and Long_2

Note 10 - Short-term and Long-term Borrowings (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Line of Credit Facilities [Table Text Block]	(in thousands) Line Limit In Use on September 30, 2019 Restricted due to Outstanding Letters of Credit Available on September 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 35,837 $ - $ 94,163 $ 120,785 OTP Credit Agreement 170,000 73,160 16,561 80,279 160,316 Total $ 300,000 $ 108,997 $ 16,561 $ 174,442 $ 281,101
Schedule of Debt [Table Text Block]	September 30, 2019 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 73,160 $ 35,837 $ 108,997 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 394 394 Total $ 512,000 $ 80,394 $ 592,394 Less: Current Maturities net of Unamortized Debt Issuance Costs - 180 180 Unamortized Long-Term Debt Issuance Costs 1,830 369 2,199 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,170 $ 79,845 $ 590,015 Total Short-Term and Long-Term Debt (with current maturities) $ 583,330 $ 115,862 $ 699,192 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs - 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773

Note 11 - Pension Plan and Ot_2

Note 11 - Pension Plan and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 $ 4,119 $ 4,845 Interest Cost on Projected Benefit Obligation 3,603 3,363 10,809 10,089 Expected Return on Assets (5,324 ) (5,300 ) (15,973 ) (15,899 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 4 12 From Other Comprehensive Income 1 2 - 6 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 3,488 5,351 From Other Comprehensive Income 1 26 46 79 137 Net Periodic Pension Cost 2 $ 844 $ 1,512 $ 2,532 $ 4,535 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in n onservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 ) Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 313 $ 300 Interest Cost on Projected Benefit Obligation 433 399 1,301 1,197 Amortization of Prior-Service Cost: From Regulatory Asset 2 4 4 12 From Other Comprehensive Income 1 4 10 12 29 Amortization of Net Actuarial Loss: From Regulatory Asset 31 66 93 200 From Other Comprehensive Income 1 87 166 262 496 Net Periodic Pension Cost 2 $ 661 $ 745 $ 1,985 $ 2,234 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in n onservice cost components of postretirement benefits 557 645 1,672 1,934 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 $ 964 $ 1,145 Interest Cost on Projected Benefit Obligation 770 646 2,312 1,937 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 1,178 1,236 From Other Comprehensive Income 1 10 11 29 32 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,451 $ 4,483 $ 4,350 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) $ (134 ) $ (110 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in n onservice cost components of postretirement benefits 889 768 2,614 2,436

Note 12 - Fair Value of Finan_2

Note 12 - Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Fair Value, by Balance Sheet Grouping [Table Text Block]	September 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 921 $ 921 $ 861 $ 861 Short-Term Debt (108,997 ) (108,997 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,195 ) (663,761 ) (590,174 ) (601,513 )

Note 14 - Income Tax Expense (T

Note 14 - Income Tax Expense (Tables)	9 Months Ended
	Sep. 30, 2019
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 29,681 $ 30,632 $ 80,402 $ 82,391 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 7,717 $ 7,964 $ 20,905 $ 21,422 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (933 ) (838 ) (2,690 ) (2,932 ) Research and Development Tax Credits (612 ) (202 ) (987 ) (562 ) Excess Tax Deduction – Equity Method Stock Awards - (73 ) (827 ) (698 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (774 ) (774 ) Reconciliation and Prior Period Adjustments (688 ) 2,109 (722 ) 2,028 Corporate Owned Life Insurance (50 ) (332 ) (609 ) (360 ) Allowance for Funds Used During Construction – Equity (239 ) (138 ) (419 ) (416 ) Federal Production Tax Credits - (707 ) - (2,757 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (1 ) (166 ) 30 (213 ) Income Tax Expense $ 4,936 $ 7,359 $ 13,907 $ 14,207 Effective Income Tax Rate 16.6 % 24.0 % 17.3 % 17.2 %
Summary of Income Tax Contingencies [Table Text Block]	(in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Prior Years 37 6 Increases Related to Tax Positions for Current Year 153 113 Uncertain Positions Resolved During Year (170 ) (186 ) Balance on September 30 $ 1,302 $ 617

Note 1 - Summary of Significa_3

Note 1 - Summary of Significant Accounting Policies (Details Textual) - USD ($)	Jan. 01, 2019	Sep. 30, 2019	Dec. 31, 2018
Goodwill, Impairment Loss			$ 0
Goodwill, Period Increase (Decrease), Total		$ 0
Accounting Standards Update 2018-02 [Member]
Tax Cuts and Jobs Act, Reclassification of Stranded Tax Effect From AOCI to Retained Earnings	$ 784,000
Coyote Creek Mining Company, L.L.C. (CCMC) [Member] | Otter Tail Power Company [Member] | Lignite Sales Agreement [Member]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount		$ 51,300,000
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	Sep. 30, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 1 [Member]
Total Assets	$ 4,123	$ 2,132
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Investments	1,462	1,294
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Other Assets	2,661	838
Fair Value, Inputs, Level 2 [Member]
Total Assets	8,150	7,484
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Investments	3,378	5,898
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments	$ 4,772	$ 1,586

Note 1 - Summary of Significa_5

Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Finished Goods	$ 29,601	$ 37,130
Work in Process	18,884	20,393
Raw Material, Fuel and Supplies	48,567	48,747
Total Inventories	$ 97,052	$ 106,270

Note 1 - Summary of Significa_6

Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Gross Balance		$ 37,572
Accumulated Impairments		0
Balance	$ 37,572	37,572
Adjustments to Goodwill	0
Manufacturing [Member]
Gross Balance		18,270
Accumulated Impairments		0
Balance	18,270	18,270
Adjustments to Goodwill	0
Plastics [Member]
Gross Balance		19,302
Accumulated Impairments		0
Balance	19,302	$ 19,302
Adjustments to Goodwill	$ 0

Note 1 - Summary of Significa_7

Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Gross Carrying Amount	$ 22,645	$ 22,645
Accumulated Amortization	11,083	10,195
Net Carrying Amount	11,562	12,450
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	10,976	10,127
Net Carrying Amount	$ 11,515	$ 12,364
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	3 months	12 months
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	191 months	200 months
Other Intangible Assets [Member]
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	107	68
Net Carrying Amount	$ 47	$ 86
Remaining Amortization Periods (Month)	11 months	20 months

Note 1 - Summary of Significa_8

Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Amortization Expense – Intangible Assets	$ 296	$ 329	$ 888	$ 1,019

Note 1 - Summary of Significa_9

Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Sep. 30, 2019USD ($)
2019	$ 1,184
2020	1,133
2021	1,099
2022	1,099
2023	$ 1,099

Note 1 - Summary of Signific_10

Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018
Transactions Related to Capital Additions not Settled in Cash	$ 15,893	$ 12,059

Note 1 - Summary of Signific_11

Note 1 - Summary of Significant Accounting Policies - Effect of Stranded Tax Effect (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 22, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Other Comprehensive Income (Loss)			$ 119	$ 164	$ 432	$ (176)
AOCI, Accumulated Gain (Loss), Debt Securities, Available-for-sale, Parent [Member]
Other Comprehensive Income (Loss)		$ 71
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$ 10
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member]
Other Comprehensive Income (Loss)		(5,672)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	(794)
AOCI Attributable to Parent [Member]
Other Comprehensive Income (Loss)		$ (5,601)	$ 119	$ 164	432	$ (176)
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts	$ (784)				$ (784)

Note 2 - Segment Information (D

Note 2 - Segment Information (Details Textual)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Number of Reportable Segments			3
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member]
Number of Customers					0
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Electric [Member]
Number of Customers					1
Concentration Risk, Percentage					11.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member]
Number of Customers					5
Concentration Risk, Percentage					52.00%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member]
Number of Customers					1
Concentration Risk, Percentage					22.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member]
Number of Customers					1
Concentration Risk, Percentage					11.20%
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member]
Number of Customers					2
Concentration Risk, Percentage					39.10%
Revenue Benchmark [Member] | UNITED STATES
Concentration Risk, Percentage	98.50%	98.10%	98.70%	98.20%

Note 2 - Business Segment Infor

Note 2 - Business Segment Information - Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Total Operating Revenues	$ 228,652	$ 227,662	$ 703,827	$ 695,276
Interest charges	7,539	7,549	23,190	22,597
Income Tax Expense	4,936	7,359	13,907	14,207
Net Income (Loss)	24,745	23,273	66,495	68,184
Assets	2,180,191		2,180,191		$ 2,052,517
Operating Segments [Member] | Electric [Member]
Regulated operating revenues	114,373	105,442	344,726	332,132
Interest charges	6,300	6,509	19,566	19,586
Income Tax Expense	4,066	5,172	9,874	7,881
Net Income (Loss)	17,682	14,567	43,884	41,835
Assets	1,829,271		1,829,271		1,728,534
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	100,345	88,750	303,276	287,330
Changes in Accrued ARP Revenues	(921)	(317)	(1,601)	(2,757)
Regulated operating revenues	99,424	88,433	301,675	284,573
Operating Segments [Member] | Electric [Member] | Electric Transmission [Member]
Revenue from Contracts with Customers	11,692	12,569	34,023	35,785
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	1,631	2,826	4,099	6,380
Operating Segments [Member] | Electric [Member] | Product and Service, Other [Member]
Revenue from Contracts with Customers	1,626	1,614	4,929	5,394
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	65,722	67,027	217,040	203,843
Interest charges	561	555	1,791	1,664
Income Tax Expense	285	799	2,888	3,040
Net Income (Loss)	3,155	3,022	11,987	10,769
Assets	206,835		206,835		187,556
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	56,255	55,864	185,520	170,179
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	8,088	8,790	26,486	26,986
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	1,379	2,373	5,034	6,678
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	48,566	55,203	142,100	159,332
Interest charges	197	150	561	460
Income Tax Expense	1,914	2,276	5,287	6,897
Net Income (Loss)	5,397	6,432	14,918	19,505
Assets	97,459		97,459		91,630
Corporate and Eliminations [Member]
Interest charges	481	335	1,272	887
Income Tax Expense	(1,329)	(888)	(4,142)	(3,611)
Net Income (Loss)	(1,489)	(748)	(4,294)	(3,925)
Assets	46,626		46,626		$ 44,797
Intersegment Eliminations [Member]
Regulated operating revenues	$ (9)	$ (10)	$ (39)	$ (31)

Note 3 - Rate and Regulatory _3

Note 3 - Rate and Regulatory Matters (Details Textual)	Nov. 01, 2019	Aug. 30, 2019USD ($)	Jun. 28, 2019USD ($)	Jun. 24, 2019USD ($)	Jun. 16, 2019USD ($)	Jun. 11, 2019USD ($)	May 30, 2019USD ($)	Apr. 01, 2019USD ($)	Dec. 01, 2018	Oct. 16, 2018	Sep. 26, 2018USD ($)	Apr. 20, 2018USD ($)	Mar. 23, 2018USD ($)	Mar. 22, 2018USD ($)	Nov. 16, 2016USD ($)	Sep. 28, 2016	May 25, 2016	Feb. 12, 2015	Nov. 06, 2014	Nov. 12, 2013	Jun. 30, 2016	Dec. 22, 2015	Sep. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017	Oct. 24, 2019USD ($)	Mar. 01, 2018USD ($)	Dec. 20, 2017USD ($)	Nov. 02, 2017USD ($)	May 01, 2017	Dec. 31, 2016USD ($)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent																										21.00%	35.00%
Regulatory Liabilities, Total																							$ 245,092,000		$ 245,092,000	$ 227,207,000
Minnesota1 [Member]
Effect of Tax Cuts and Jobs Act, Refund to Customers																							11,500,000
NORTH DAKOTA
Accrued Refund Liabilities Resulting from Tax Rate Reduction																								$ 800,000
Federal Energy Regulatory Commission [Member]
Accrued Refund Liabilities Resulting from Tax Rate Reduction																							200,000		200,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Current Return on Equity Used in Transmission Rates																10.32%				12.38%		10.32%
Proposed Reduced Return on Equity Used in Transmission Rates																		8.67%		9.15%	9.70%
Additional Incentive Basis Point																			0.50%
Expected Percentage of Return on Equity										10.41%						10.82%
Regulatory Liabilities, Total																							1,600,000		1,600,000								$ 2,700,000
Contract with Customer, Refund Liability, Total																							1,600,000		1,600,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | Maximum [Member]
Proposed Reduced Return on Equity Used in Transmission Rates										13.08%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																																7.5056%
Percentage of Allowed Rate of Return on Equity																																9.41%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member]
Utility Incentive Percentage in Next Rolling Twelve Months																	13.50%
Utility Incentive Percentage in Next Rolling Year Two																	12.00%
Utility Incentive Percentage in Next Rolling Year Three																	10.00%
Assumed Savings of Utility																	1.70%
Financial Incentive, Maximum Percentage of Spending, Year One																	40.00%
Financial Incentive, Maximum Percentage of Spending, Year Two																	35.00%
Financial Incentive, Maximum Percentage of Spending, Year Three																	30.00%
Expected Rate of Financial Incentive Reduction																	50.00%
Financial Incentives Recognized During Period								$ 3,000,000
Financial Incentive Offered to MPUC				$ 4,000,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member]
Financial Incentive Request Approved																												$ 3,000,000
Otter Tail Power Company [Member] | Minnesota1 [Member]
Environmental Cost Recovery Rider Rate									0.00%
Otter Tail Power Company [Member] | Minnesota1 [Member] | Transmission Cost Recovery Rider [Member]
Loss Contingency, Estimate of Possible Loss																							2,600,000		2,600,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																															7.97%
Percentage of Allowed Rate of Return on Equity																															10.30%
General Rate Revenue Increase Requested																														$ 12,800,000	$ 13,100,000
Percentage of Increase in Base Rate Revenue Requested																															8.72%
Public Utilities, Interim Rate Requirement, Decrease in Amount																													$ 4,500,000
Public Utilities, Interim Rate Requirement, Amount																													$ 8,300,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member]
Percentage of Allowed Rate of Return on Equity													10.30%
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 4,600,000		$ 7,100,000	$ 13,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage											3.10%		4.80%
General Rate Revenue Increase Requested, Decrease													$ 6,000,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform													4,800,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform													$ 1,200,000
Percentage of Requested Allowed Rate of Return on Equity											9.77%
Equity to Total Capitalization Ratio Basis for Return on Equity											52.50%
Otter Tail Power Company [Member] | North Dakota 1 [Member] | Subsequent Event [Member]
Environmental Cost Recovery Rider Rate	0.00%
Otter Tail Power Company [Member] | North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Annual Revenue Requesting Recovery		$ 5,700,000
Number of New Projects Included in Request for Recovery		7
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							$ 2,200,000																	$ 1,000,000
Understated Amount of OTP's Electric Transmission Plant in Service			$ 44,000,000
Annual Revenue Requirement Shortfall Resulted from Understatement			341,000
Increase in Non-fuel Annual Revenue Resulted from Increased in General Rate Case			$ 2,600,000
Increase in Non-fuel Annual Revenue Resulted from Increased in General Rate Case, Percentage			7.70%
Non-fuel Annual Revenue Increased, Perecenage of Adjusted Requsted Annual Revenue			69.00%
Adjusted Requested Annual Revenue Increased, Amount			$ 3,700,000
Adjusted Requested Annual Revenue Increased, Percentage			11.10%
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] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member]
Current Project Cost																									$ 106,000,000
Expanded Capacity of Projects																									345
Extended Distance of Transmission Line																									162
Percentage of Assets of Project																									100.00%
Otter Tail Power Company [Member] | Astoria Station Project [Member]
Expanded Capacity of Projects (MW)																									245
Current Project Capitalized Cost																									$ 36,800,000
Expected Project Cost																							158,000,000		158,000,000
Otter Tail Power Company [Member] | Merricourt Project [Member] | EDF [Member]
Expanded Capacity of Projects (MW)															150
Expected Project Cost																							$ 258,000,000		258,000,000
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 Cost																									$ 54,800,000

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		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenues recorded under rate riders	$ 4,399	$ 8,377	$ 15,816	$ 24,933
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	1,518	1,488	4,246	4,300
Minnesota1 [Member] | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders	1,316	817	3,949	2,001
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders	(284)	(1,196)	301	(1,683)
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders	0	24	(1)	(25)
North Dakota 1 [Member] | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders	(20)	2,220	616	6,266
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders	908	1,922	3,554	5,149
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders	(7)	1,823	556	5,474
North Dakota 1 [Member] | Generation Cost Recovery [Member]
Revenues recorded under rate riders	137	0	607	0
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	100	238	440	589
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders	743	496	1,587	1,282
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders	(2)	545	(29)	1,580
South Dakota 1 [Member] | Phase-in Rate Plan Recovery [Member]
Revenues recorded under rate riders	$ (10)	$ 0	$ (10)	$ 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] $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)kWh	Sep. 30, 2018USD ($)
Annual Revenue	$ 4,399	$ 8,377	$ 15,816	$ 24,933
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	1,518	1,488	$ 4,246	4,300
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member]
A - Approval Date			Oct. 24, 2019
Effective Date Requested or Approved			Dec. 1, 2019
Annual Revenue			$ 11,926
Rate rider rate (Kilowatt-Hour) | kWh			0.00710
Effective Date Requested or Approved			Dec. 1, 2019
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
A - Approval Date			Oct. 4, 2018
Effective Date Requested or Approved			Nov. 1, 2018
Annual Revenue			$ 10,283
Rate rider rate (Kilowatt-Hour) | kWh			0.00600
Effective Date Requested or Approved			Nov. 1, 2018
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member]
A - Approval Date			Sep. 15, 2017
Effective Date Requested or Approved			Oct. 1, 2017
Annual Revenue			$ 9,868
Rate rider rate (Kilowatt-Hour) | kWh			0.00536
Effective Date Requested or Approved			Oct. 1, 2017
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	(284)	(1,196)	$ 301	(1,683)
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member]
Effective Date Requested or Approved			Jun. 1, 2019
Annual Revenue			$ 6,475
R - Request Date			Nov. 30, 2018
Rate			Various
Effective Date Requested or Approved			Jun. 1, 2019
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario B [Member]
Annual Revenue			$ 2,708
Rate			Various
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date			Oct. 30, 2017
Effective Date Requested or Approved			Nov. 1, 2017
Annual Revenue			$ (3,311)
Rate			Various
Effective Date Requested or Approved			Nov. 1, 2017
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	0	24	$ (1)	(25)
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date			Oct. 30, 2017
Effective Date Requested or Approved			Nov. 1, 2017
Annual Revenue			$ (1,943)
Rate of base			(0.935%)
Effective Date Requested or Approved			Nov. 1, 2017
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
A - Approval Date			Nov. 29, 2018
Effective Date Requested or Approved			Dec. 1, 2018
Annual Revenue			$ 0
Rate of base			0.00%
Effective Date Requested or Approved			Dec. 1, 2018
Minnesota1 [Member] | Renewable Resource Adjustment [Member]
Annual Revenue	1,316	817	$ 3,949	2,001
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
A - Approval Date			Oct. 30, 2017
Effective Date Requested or Approved			Nov. 1, 2017
Annual Revenue			$ 1,279
Rate rider rate (Kilowatt-Hour) | kWh			0.00049
Effective Date Requested or Approved			Nov. 1, 2017
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
A - Approval Date			Aug. 29, 2018
Effective Date Requested or Approved			Nov. 1, 2018
Annual Revenue			$ 5,886
Rate rider rate (Kilowatt-Hour) | kWh			0.00219
Effective Date Requested or Approved			Nov. 1, 2018
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update - Revised [Member]
Effective Date Requested or Approved			Nov. 1, 2019
Annual Revenue			$ 12,506
Rate rider rate (Kilowatt-Hour) | kWh			0.00467
R - Request Date			Sep. 30, 2019
Effective Date Requested or Approved			Nov. 1, 2019
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	908	1,922	$ 3,554	5,149
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
R - Request Date			Aug. 30, 2019
Rate			Various
Effective Date Requested or Approved			Jan. 1, 2020
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date			Feb. 27, 2018
Effective Date Requested or Approved			Mar. 1, 2018
Annual Revenue			$ 7,469
Rate			Various
Effective Date Requested or Approved			Mar. 1, 2018
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member]
A - Approval Date			Dec. 6, 2018
Effective Date Requested or Approved			Feb. 1, 2019
Annual Revenue			$ 4,801
Rate			Various
Effective Date Requested or Approved			Feb. 1, 2019
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date			Nov. 29, 2017
Effective Date Requested or Approved			Jan. 1, 2018
Annual Revenue			$ 7,959
Rate			Various
Effective Date Requested or Approved			Jan. 1, 2018
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	(7)	1,823	$ 556	5,474
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date			Dec. 20, 2017
Effective Date Requested or Approved			Jan. 1, 2018
Annual Revenue			$ 8,537
Rate of base			6.629%
Effective Date Requested or Approved			Jan. 1, 2018
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
A - Approval Date			Dec. 19, 2018
Effective Date Requested or Approved			Feb. 1, 2019
Annual Revenue			$ (378)
Rate of base			(0.31%)
Effective Date Requested or Approved			Feb. 1, 2019
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
A - Approval Date			Oct. 22, 2019
Effective Date Requested or Approved			Nov. 1, 2019
Annual Revenue			$ 0
Rate of base			0.00%
Effective Date Requested or Approved			Nov. 1, 2019
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date			Feb. 27, 2018
Effective Date Requested or Approved			Mar. 1, 2018
Annual Revenue			$ 7,718
Rate of base			5.593%
Effective Date Requested or Approved			Mar. 1, 2018
North Dakota 1 [Member] | Renewable Resource Adjustment [Member]
Annual Revenue	(20)	2,220	$ 616	6,266
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
A - Approval Date			Dec. 20, 2017
Effective Date Requested or Approved			Jan. 1, 2018
Annual Revenue			$ 9,989
Rate of base			7.756%
Effective Date Requested or Approved			Jan. 1, 2018
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member]
A - Approval Date			May 1, 2019
Effective Date Requested or Approved			Jun. 1, 2019
Annual Revenue			$ (235)
Rate of base			(0.224%)
Effective Date Requested or Approved			Jun. 1, 2019
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date			Feb. 27, 2018
Effective Date Requested or Approved			Mar. 1, 2018
Annual Revenue			$ 9,650
Rate of base			7.493%
Effective Date Requested or Approved			Mar. 1, 2018
North Dakota 1 [Member] | Generation Cost Recovery [Member]
Annual Revenue	137	0	$ 607	0
North Dakota 1 [Member] | Generation Cost Recovery [Member] | The 2019 Initial Request [Member]
A - Approval Date			May 15, 2019
Effective Date Requested or Approved			Jul. 1, 2019
Annual Revenue			$ 2,720
Rate of base			2.547%
Effective Date Requested or Approved			Jul. 1, 2019
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	100	238	$ 440	589
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue	743	496	$ 1,587	1,282
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
A - Approval Date			Feb. 20, 2019
Effective Date Requested or Approved			Mar. 1, 2019
Annual Revenue			$ 1,638
Rate			Various
Effective Date Requested or Approved			Mar. 1, 2019
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date			Feb. 28, 2018
Effective Date Requested or Approved			Mar. 1, 2018
Annual Revenue			$ 1,779
Rate			Various
Effective Date Requested or Approved			Mar. 1, 2018
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Rate Reset [Member]
A - Approval Date			Sep. 17, 2019
Effective Date Requested or Approved			Oct. 1, 2019
Annual Revenue			$ 2,046
Rate			Various
Effective Date Requested or Approved			Oct. 1, 2019
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
A - Approval Date			Oct. 18, 2018
Effective Date Requested or Approved			Oct. 18, 2018
Annual Revenue			$ 1,171
Rate			Various
Effective Date Requested or Approved			Oct. 18, 2018
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date			Feb. 17, 2017
Effective Date Requested or Approved			Mar. 1, 2017
Annual Revenue			$ 2,053
Rate			Various
Effective Date Requested or Approved			Mar. 1, 2017
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue	$ (2)	$ 545	$ (29)	$ 1,580
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date			Oct. 13, 2017
Effective Date Requested or Approved			Nov. 1, 2017
Annual Revenue			$ 2,082
Rate rider rate (Kilowatt-Hour) | kWh			0.00483
Effective Date Requested or Approved			Nov. 1, 2017
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
A - Approval Date			Oct. 18, 2018
Effective Date Requested or Approved			Oct. 18, 2018
Annual Revenue			$ (189)
Rate rider rate (Kilowatt-Hour) | kWh			(0.00075)
Effective Date Requested or Approved			Oct. 18, 2018
South Dakota 1 [Member] | Phase-In Rate Plan [Member] | The 2019 Initial Request [Member]
A - Approval Date			Aug. 21, 2019
Effective Date Requested or Approved			Sep. 1, 2019
Annual Revenue			$ 864
Rate of base			3.345%
Effective Date Requested or Approved			Sep. 1, 2019

Note 4 - Regulatory Assets an_3

Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		9 Months Ended	12 Months Ended
		Sep. 30, 2019	Dec. 31, 2018
Regulatory Assets - Current		$ 12,667	$ 17,225
Regulatory Assets - Long -Term		130,551	135,257
Regulatory Assets - Total		143,218	152,482
Regulatory Liabilities - Current		6,311	738
Regulatory Liabilities - Long -Term		238,781	226,469
Regulatory Liabilities, Total		245,092	227,207
Net Regulatory Asset Position - Current		6,356	16,487
Net Regulatory Asset Position - Long-Term		(108,230)	(91,212)
Net Regulatory Asset/(Liability) Position		(101,874)	(74,725)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current		0	0
Regulatory Liabilities - Long -Term		141,337	142,779
Regulatory Liabilities, Total		$ 141,337	$ 142,779
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current		$ 0	$ 0
Regulatory Liabilities - Long -Term		96,981	83,229
Regulatory Liabilities, Total		$ 96,981	$ 83,229
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues - Minnesota [Member]
Regulatory Liabilities - Current		$ 3,836
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 3,836
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		3 months
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current			$ 121
Regulatory Liabilities - Long -Term			0
Regulatory Liabilities, Total			$ 121
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			12 months
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 684	$ 177
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities, Total		$ 684	$ 177
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		8 months	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 601	$ 60
Regulatory Liabilities - Long -Term		0	0
Regulatory Liabilities, Total		$ 601	$ 60
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		2 months	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 537
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 537
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		2 months
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current		$ 0	$ 0
Regulatory Liabilities - Long -Term		342	166
Regulatory Liabilities, Total		$ 342	$ 166
Regulatory Liabilities - Remaining Recovery/Refund Period		see below	see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current		$ 140	$ 0
Regulatory Liabilities - Long -Term		47	187
Regulatory Liabilities, Total		$ 187	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		15 months	24 months
Refundable Fuel Clause Adjustment Revenues – North Dakota [Member]
Regulatory Liabilities - Current		$ 305
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 305
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current			$ 168
Regulatory Liabilities - Long -Term			0
Regulatory Liabilities, Total			$ 168
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current			$ 207
Regulatory Liabilities - Long -Term			0
Regulatory Liabilities, Total			$ 207
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			12 months
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 151
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 151
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 5
Regulatory Liabilities - Long -Term		74	108
Regulatory Liabilities, Total		$ 80	$ 113
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		171 months	180 months
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 6,355	$ 6,346
Regulatory Assets - Long -Term	[1]	113,657	118,433
Regulatory Assets - Total	[1]	$ 120,012	$ 124,779
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]	$ 0	$ 0
Regulatory Assets - Long -Term	[1]	7,571	7,169
Regulatory Assets - Total	[1]	$ 7,571	$ 7,169
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 243	$ 5,995
Regulatory Assets - Long -Term	[2]	5,339	3,285
Regulatory Assets - Total	[2]	$ 5,582	$ 9,280
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	24 months	21 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 2,856	$ 444
Regulatory Assets - Long -Term	[2]	0	0
Regulatory Assets - Total	[2]	$ 2,856	$ 444
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	12 months	12 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]	1,525	986
Regulatory Assets - Total	[1]	$ 1,525	$ 986
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 972	$ 1,661
Regulatory Assets - Long -Term	[1]	186	743
Regulatory Assets - Total	[1]	$ 1,158	$ 2,404
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	15 months	24 months
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 706	$ 681
Regulatory Assets - Long -Term	[1]	409	947
Regulatory Assets - Total	[1]	$ 1,115	$ 1,628
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	19 months	28 months
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 203	$ 207
Regulatory Assets - Long -Term	[1]	598	753
Regulatory Assets - Total	[1]	$ 801	$ 960
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	156 months	165 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]	$ 60	$ 240
Regulatory Assets - Long -Term	[1]	711	0
Regulatory Assets - Total	[1]	$ 771	$ 240
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	27 months	12 months
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 418	$ 178
Regulatory Assets - Long -Term	[1]	0	0
Regulatory Assets - Total	[1]	$ 418	$ 178
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	12 months	12 months
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 116	$ 100
Regulatory Assets - Long -Term	[1]	234	342
Regulatory Assets - Total	[1]	$ 350	$ 442
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	36 months	53 months
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 339	$ 455
Regulatory Assets - Long -Term	[1]	0	0
Regulatory Assets - Total	[1]	$ 339	$ 455
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	12 months	12 months
Minnesota SPP Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]	$ 0	$ 0
Regulatory Assets - Long -Term	[1]	270	176
Regulatory Assets - Total	[1]	$ 270	$ 176
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
South Dakota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 193
Regulatory Assets - Long -Term	[2]	0
Regulatory Assets - Total	[2]	$ 193
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	5 months
Minnesota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 4	$ 121
Regulatory Assets - Long -Term	[2]	0	0
Regulatory Assets - Total	[2]	$ 4	$ 121
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	3 months	12 months
Recoverable Fuel and Purchased Power Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 124
Regulatory Assets - Long -Term	[1]	0
Regulatory Assets - Total	[1]	$ 124
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	12 months
Deferred Income Taxes [Member]
Regulatory Assets - Current	[1]		$ 0
Regulatory Assets - Long -Term	[1]		2,423
Regulatory Assets - Total	[1]		$ 2,423
Regulatory Assets - Remaining Recovery/Refund Period	[1]		asset lives
North Dakota Generation Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 78
Regulatory Assets - Long -Term	[2]	0
Regulatory Assets - Total	[2]	$ 78
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	9 months
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 452
Regulatory Assets - Long -Term	[2]		0
Regulatory Assets - Total	[2]		$ 452
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		12 months
Deferred Lease Expenses [Member]
Regulatory Assets - Current	[1]	$ 0
Regulatory Assets - Long -Term	[1]	51
Regulatory Assets - Total	[1]	$ 51
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	42 months
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]		$ 328
Regulatory Assets - Long -Term	[1]		0
Regulatory Assets - Total	[1]		$ 328
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]		4 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 17
Regulatory Assets - Long -Term	[2]		0
Regulatory Assets - Total	[2]		$ 17
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		12 months
South Dakota Phase-in Rate Plan Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 39
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 39
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 months
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 12
Regulatory Liabilities - Long -Term		0
Regulatory Liabilities, Total		$ 12
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		12 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 - Reconciliation of Company's Common Shares (Details)	9 Months Ended
	Sep. 30, 2019shares
Common Shares Outstanding, beginning balance (in shares)	39,664,884
Vesting of Restricted Stock Units (in shares)	27,125
Restricted Stock Issued to Directors (in shares)	15,700
Directors Deferred Compensation (in shares)	594
Shares Withheld for Individual Income Tax Requirements (in shares)	(55,224)
Common Shares Outstanding, ending balance (in shares)	39,755,277
Performance Awards 2016 [Member]
Executive Stock Performance Awards (2016 shares earned) (in shares)	102,198

Note 5 - Common Shares and Ea_4

Note 5 - Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Weighted Average Common Shares Outstanding – Basic (in shares)	39,714,672	39,621,524	39,694,677	39,592,705
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares)	149,023	206,268	147,106	210,691
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	68,138	58,680	63,902	58,475
Nonvested Restricted Shares (in shares)	13,107	14,761	14,896	17,712
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	1,799	2,332	1,999	2,522
Total Dilutive Shares (in shares)	232,067	282,041	227,903	289,400
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,946,739	39,903,565	39,922,580	39,882,105

Note 6 - Share-based Payments_2

Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions	Feb. 13, 2019	Jul. 31, 2019	Sep. 30, 2019
Employee Stock Purchase Plan, Employee Discount		15.00%
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			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	55,600
Period Specified for Average Adjusted Return	3 years
Number of Trading Days	20 days
Number of Shares Authorized for Actual Payment	83,400
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member]
Percentage of Target Amount as Actual Payment	0.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member]
Percentage of Target Amount as Actual Payment	150.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800

Note 6 - Share-based Payments -

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details)	9 Months Ended
	Sep. 30, 2019$ / sharesshares
Performance Shares [Member] | The 2014 Stock Incentive Plan [Member] | February 13, 2019 [Member]
Shares/units granted (in shares) | shares	47,800
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 42.875
Shares/units granted, vesting date	December 31, 2021
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member]
Shares/units granted, vesting date	December 31, 2021
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member] | February 13, 2019 [Member]
Shares/units granted (in shares) | shares	7,800
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 45.885
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | February 13, 2019 [Member] | Executive Officer [Member]
Shares/units granted (in shares) | shares	15,600
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 49.6225
Shares/units granted, vesting date	25% per year through February 6, 2023
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | April 8, 2019 [Member] | Key Employee [Member]
Shares/units granted (in shares) | shares	13,270
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 44.45
Shares/units granted, vesting date	100% on April 8, 2023
Restricted Stock [Member] | The 2014 Stock Incentive Plan [Member] | April 8, 2019 [Member] | Nonemployee Directors [Member]
Shares/units granted (in shares) | shares	15,700
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 49.73
Shares/units granted, vesting date	33% per year through April 8, 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]	9 Months Ended
	Sep. 30, 2019
Restricted Stock Units (RSUs) [Member] | February 13, 2019 [Member] | Executive Officer [Member]
Shares/units granted, vesting percentage	25.00%
Restricted Stock Units (RSUs) [Member] | April 8, 2019 [Member] | Key Employee [Member]
Shares/units granted, vesting percentage	100.00%
Restricted Stock [Member] | April 8, 2019 [Member] | Nonemployee Directors [Member]
Shares/units granted, vesting percentage	33.00%

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		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Stock compensation expense	$ 1,301	$ 1,149	$ 5,245	$ 3,402
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	743	718	3,274	2,037
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	189	174	999	596
Restricted Stock Units (RSUs) [Member] | Key Employee [Member]
Stock compensation expense	112	92	346	257
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense	0	0	0	16
Restricted Stock [Member] | Nonemployee Directors [Member]
Stock compensation expense	203	165	572	496
Employee Stock Purchase Plan [Member]
Stock compensation expense	$ 54	$ 0	$ 54	$ 0

Note 7 - Retained Earnings an_2

Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($)	Jul. 19, 2019	Sep. 30, 2019	Dec. 31, 2018
Capitalization, Long-term Debt and Equity, Total		$ 1,346,520,000	$ 1,318,865,000
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio		52.20%
Net Assets Restricted from Distribution		$ 497,000,000
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, Approved Equity Capital Structure, Percentage	46.00%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member]
Public Utilities, Approved Equity Capital Structure, Percentage	56.20%

Note 8 - Leases (Details Textua

Note 8 - Leases (Details Textual) - USD ($) $ in Thousands	Sep. 30, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating Lease, Right-of-Use Asset	$ 21,953		$ 0
Operating Lease, Liability, Total	$ 22,390		$ 20,369
Operating Lease, Weighted Average Remaining Lease Term	6 years 2 months 12 days
Operating Lease, Weighted Average Discount Rate, Percent	5.30%
Minimum [Member]
Lessee, Operating Lease, Term of Contract	1 year
Maximum [Member]
Lessee, Operating Lease, Term of Contract	10 years
Accounting Standards Update 2016-02 [Member]
Operating Lease, Right-of-Use Asset		$ 20,000
Operating Lease, Liability, Total		$ 20,000

Note 8 - Leases - Lease Assets

Note 8 - Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Gross	$ 24,959
Accumulated Amortization	(3,006)
Net of Accumulated Amortization	21,953	$ 0
Current Operating Lease Liabilities	4,006	0
Long-Term Operating Lease Liabilities	18,384	0
Total Lease Liabilities	22,390	$ 20,369
Electric [Member]
Gross	3,557
Accumulated Amortization	(778)
Net of Accumulated Amortization	2,779
Current Operating Lease Liabilities	985
Long-Term Operating Lease Liabilities	2,081
Total Lease Liabilities	3,066
Manufacturing [Member]
Gross	19,967
Accumulated Amortization	(1,836)
Net of Accumulated Amortization	18,131
Current Operating Lease Liabilities	2,541
Long-Term Operating Lease Liabilities	15,686
Total Lease Liabilities	18,227
Plastics [Member]
Gross	666
Accumulated Amortization	(294)
Net of Accumulated Amortization	372
Current Operating Lease Liabilities	326
Long-Term Operating Lease Liabilities	45
Total Lease Liabilities	371
Corporate Segment [Member]
Gross	769
Accumulated Amortization	(98)
Net of Accumulated Amortization	671
Current Operating Lease Liabilities	154
Long-Term Operating Lease Liabilities	572
Total Lease Liabilities	$ 726

Note 8 - Leases - Lease Obligat

Note 8 - Leases - Lease Obligations (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
2019	$ 1,304
2020	4,998
2021	4,719
2022	3,697
2023	3,399
Beyond 2023	8,427
Total Minimum Obligations	26,544
Interest Component of Obligations	(4,154)
Present Value of Minimum Obligations, September 30, 2019	22,390	$ 20,369
OTP [Member]
2019	275
2020	1,115
2021	1,100
2022	206
2023	196
Beyond 2023	448
Total Minimum Obligations	3,340
Interest Component of Obligations	(274)
Present Value of Minimum Obligations, September 30, 2019	3,066	3,609
Nonelectric Companies [Member]
2019	1,029
2020	3,883
2021	3,619
2022	3,491
2023	3,203
Beyond 2023	7,979
Total Minimum Obligations	23,204
Interest Component of Obligations	(3,880)
Present Value of Minimum Obligations, September 30, 2019	$ 19,324	$ 16,760

Note 8 - Leases - Operating Lea

Note 8 - Leases - Operating Lease Obligation (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2019USD ($)
Operating Lease Obligations, beginning balance	$ 20,369
Non-cash Acquisition of Right-of-Use Assets	5,292
Lease Modifications	(164)
Lease Obligation Payments	(3,931)
Interest Component of Lease Obligation Payment	824
Operating Lease Obligations, ending balance	22,390
OTP [Member]
Operating Lease Obligations, beginning balance	3,609
Non-cash Acquisition of Right-of-Use Assets	177
Lease Modifications	0
Lease Obligation Payments	(845)
Interest Component of Lease Obligation Payment	125
Operating Lease Obligations, ending balance	3,066
Nonelectric Companies [Member]
Operating Lease Obligations, beginning balance	16,760
Non-cash Acquisition of Right-of-Use Assets	5,115
Lease Modifications	(164)
Lease Obligation Payments	(3,086)
Interest Component of Lease Obligation Payment	699
Operating Lease Obligations, ending balance	$ 19,324

Note 8 - Leases - Allocation of

Note 8 - Leases - Allocation of Lease Costs (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Operating lease cost	$ 1,331	$ 4,028
Variable lease cost	64	137
Total lease cost	1,395	4,165
Fixed Assets [Member]
Operating lease cost	9	29
Variable lease cost	0	0
Total lease cost	9	29
Production Fuel [Member]
Operating lease cost	244	707
Variable lease cost	0	0
Total lease cost	244	707
Cost of Sales [Member]
Operating lease cost	963	2,942
Variable lease cost	65	137
Total lease cost	1,028	3,079
Electric Operating and Maintenance Expenses [Member]
Operating lease cost	64	194
Variable lease cost	0	0
Total lease cost	64	194
Other Nonelectric Expenses [member]
Operating lease cost	51	156
Total lease cost	50	156
Variable lease cost	$ (1)	$ 0

Note 9 - Commitments and Cont_2

Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2018
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1.6
Otter Tail Power Company [Member] | Construction Programs [Member]
Contract Expiration Year	2021			2021
Long-term Purchase Commitment, Amount	$ 138.9			$ 64.5
Increase (Decrease) in Long Term Purchase Commitments	77.5
Otter Tail Power Company [Member] | Construction Programs [Member] | Forecast [Member]
Increase (Decrease) in Long Term Purchase Commitments		$ 9.7	$ 70.3
Otter Tail Power Company [Member] | Construction Programs, Unmet Project Commitments [Member]
Increase (Decrease) in Long Term Purchase Commitments	$ (5.7)
Otter Tail Power Company [Member] | Capacity and Energy Requirements [Member]
Contract Expiration Year	2042
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2040
Otter Tail Power Company [Member] | Coal Purchase Commitments 3 [Member]
Contract Expiration Year	2020
Otter Tail Power Company [Member] | OTP Land Easements [Member]
Contract Expiration Year	2034
Long-term Purchase Commitment, Amount	$ 10.4
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount				5
Long-term Purchase Commitment, Estimated Annual Payment				$ 1.6

Note 10 - Short-term and Long_3

Note 10 - Short-term and Long-term Borrowings (Details Textual) - USD ($)	Oct. 10, 2019	Oct. 31, 2019	Sep. 30, 2019	Sep. 12, 2019
Line of Credit Facility, Maximum Borrowing Capacity			$ 300,000,000
Otter Tail Corporation Credit Agreement [Member]
Line of Credit Facility, Maximum Borrowing Capacity			130,000,000
Otter Tail Corporation Credit Agreement [Member] | Subsequent Event [Member]
Line of Credit Facility, Maximum Borrowing Capacity		$ 170,000,000
Series 2019 Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 175,000,000
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount				10.00%
Debt Instrument, Prepayment, Percentage of the Principal Amount Prepaid				100.00%
Debt Instrument, Percentage of Principal Amount to be Offered for Prepayment in the Event of a Change of Control				100.00%
Debt to Total Capitalization Ratio				60.00%
Priority Debt to Total Capitalization				20.00%
Series 2019 Notes [Member] | Subsequent Event [Member] | Otter Tail Power Company [Member]
Proceeds from Notes Payable, Total	$ 100,000,000
Series 2019A Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.07%
Series 2019B Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 26,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.52%
Series 2019C Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 64,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.82%
Series 2020A Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.22%
Series 2020B Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 40,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.22%
Series 2020C Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 10,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.62%
Series 2020D Notes [Member] | Otter Tail Power Company [Member]
Debt Instrument, Face Amount				$ 15,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.92%
OTP Credit Agreement [Member]
Line of Credit Facility, Maximum Borrowing Capacity			$ 170,000,000
OTP Credit Agreement [Member] | Subsequent Event [Member] | Otter Tail Power Company [Member]
Repayments of Debt	$ 69,900,000

Note 10 - Short-term and Long_4

Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Line of Credit Facility, Maximum Borrowing Capacity	$ 300,000
In Use	108,997
Restricted due to Outstanding Letters of Credit	16,561
Available	174,442	$ 281,101
Otter Tail Corporation Credit Agreement [Member]
Line of Credit Facility, Maximum Borrowing Capacity	130,000
In Use	35,837
Restricted due to Outstanding Letters of Credit	0
Available	94,163	120,785
OTP Credit Agreement [Member]
Line of Credit Facility, Maximum Borrowing Capacity	170,000
In Use	73,160
Restricted due to Outstanding Letters of Credit	16,561
Available	$ 80,279	$ 160,316

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	Sep. 30, 2019	Dec. 31, 2018
Short-Term Debt	$ 108,997	$ 18,599
Long-Term Debt	592,394	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	180	172
Unamortized Long-Term Debt Issuance Costs	2,199	2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	590,015	590,002
Total Short-Term and Long-Term Debt (with current maturities)	699,192	608,773
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000	100,000
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	394	523
Otter Tail Power Company [Member]
Short-Term Debt	73,160	9,384
Long-Term Debt	512,000	512,000
Less: Current Maturities net of Unamortized Debt Issuance Costs	0	0
Unamortized Long-Term Debt Issuance Costs	1,830	1,942
Total Long-Term Debt net of Unamortized Debt Issuance Costs	510,170	510,058
Total Short-Term and Long-Term Debt (with current maturities)	583,330	519,442
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000	100,000
Parent Company [Member]
Short-Term Debt	35,837	9,215
Long-Term Debt	80,394	80,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	180	172
Unamortized Long-Term Debt Issuance Costs	369	407
Total Long-Term Debt net of Unamortized Debt Issuance Costs	79,845	79,944
Total Short-Term and Long-Term Debt (with current maturities)	115,862	89,331
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 394	$ 523

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)	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.07%	4.07%
Long-Term Debt, Due Date	Feb. 7, 2048	Feb. 7, 2048
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

Note 11 - Pension Plan and Ot_3

Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2019	Jan. 31, 2019
Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 12.5	$ 10

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		9 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,373	$ 1,615	$ 4,119	$ 4,845
Interest Cost on Projected Benefit Obligation		3,603	3,363	10,809	10,089
Expected Return on Assets		(5,324)	(5,300)	(15,973)	(15,899)
From Regulatory Asset		1	4	4	12
From Other Comprehensive Income	[1]	2	0	6	0
From Regulatory Asset		1,163	1,784	3,488	5,351
From Other Comprehensive Income	[1]	26	46	79	137
Net Periodic Pension Cost	[2]	844	1,512	2,532	4,535
From Other Comprehensive Income	[1]	26	46	79	137
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		333	455	1,059	1,162
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		1,007	1,119	2,961	3,561
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		33	41	99	121
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		(128)	(29)	(408)	(74)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		(401)	(74)	(1,179)	(235)
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		104	100	313	300
Interest Cost on Projected Benefit Obligation		433	399	1,301	1,197
From Regulatory Asset		2	4	4	12
From Other Comprehensive Income	[3]	4	10	12	29
From Regulatory Asset		31	66	93	200
From Other Comprehensive Income	[3]	87	166	262	496
Net Periodic Pension Cost	[4]	661	745	1,985	2,234
From Other Comprehensive Income	[3]	87	166	262	496
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		26	24	78	74
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		78	76	235	226
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		557	645	1,672	1,934
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		321	382	964	1,145
Interest Cost on Projected Benefit Obligation		770	646	2,312	1,937
From Regulatory Asset		393	412	1,178	1,236
From Other Comprehensive Income	[1]	10	11	29	32
Net Periodic Pension Cost	[5]	1,494	1,451	4,483	4,350
From Other Comprehensive Income	[1]	10	11	29	32
Effect of Medicare Part D Subsidy		(45)	(37)	(134)	(110)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		78	108	248	275
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		235	264	693	841
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		8	10	23	29
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		284	301	905	769
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		$ 889	$ 768	$ 2,614	$ 2,436
[1]	Corporate cost included in nonservice cost components of postretirement benefits.
[2]	Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in nonservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 )
[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 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in nonservice cost components of postretirement benefits 557 645 1,672 1,934
[5]	Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in nonservice cost components of postretirement benefits 889 768 2,614 2,436

Note 12 - Fair Value of Finan_3

Note 12 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Otter Tail Corporation Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.50%	1.50%
OTP Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.25%	1.25%

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	Sep. 30, 2019	Dec. 31, 2018
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 921	$ 861
Short-Term Debt	(108,997)	(18,599)
Long-Term Debt including Current Maturities	(590,195)	(590,174)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	921	861
Short-Term Debt	(108,997)	(18,599)
Long-Term Debt including Current Maturities	$ (663,761)	$ (601,513)

Note 14 - Income Tax Expense (D

Note 14 - Income Tax Expense (Details Textual) $ in Thousands	9 Months Ended
	Sep. 30, 2019USD ($)
Period for Unrecognized Tax Benefits Not Expected Change	12 months
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ 0
Domestic Tax Authority [Member]
Open Tax Year	2016 2017 2018
State and Local Jurisdiction [Member] | Minnesota Department of Revenue [Member]
Open Tax Year	2015 2016 2017 2018

Note 14 - Income Tax Expense -

Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Income Before Income Taxes	$ 29,681	$ 30,632	$ 80,402	$ 82,391
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%)	7,717	7,964	20,905	21,422
Differences Reversing in Excess of Federal Rates	(933)	(838)	(2,690)	(2,932)
Research and Development Tax Credits	(612)	(202)	(987)	(562)
Excess Tax Deduction – Equity Method Stock Awards	0	(73)	(827)	(698)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(258)	(774)	(774)
Reconciliation and Prior Period Adjustments	(688)	2,109	(722)	2,028
Corporate Owned Life Insurance	(50)	(332)	(609)	(360)
Allowance for Funds Used During Construction – Equity	(239)	(138)	(419)	(416)
Federal Production Tax Credits	0	(707)	0	(2,757)
Other Comprehensive Income Deferred Tax Rate Adjustment	0	0	0	(531)
Other Items – Net	(1)	(166)	30	(213)
Income Tax Expense	$ 4,936	$ 7,359	$ 13,907	$ 14,207
Effective Income Tax Rate	16.60%	24.00%	17.30%	17.20%

Note 14 - Income Tax Expense _2

Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Composite Federal and State Statutory Rate	26.00%	26.00%	26.00%	26.00%

Note 14 - Income Tax Expense _3

Note 14 - Income Tax Expense - Unrecognized Tax Benefit Activity (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Balance, beginning	$ 1,282	$ 684
Increases Related to Tax Positions for Prior Years	37	6
Increases Related to Tax Positions for Current Year	153	113
Uncertain Positions Resolved During Year	(170)	(186)
Balance, ending	$ 1,302	$ 617