Otter Tail (OTTR) 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document Information [Line Items]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	0001466593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		39,754,652
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false

Consolidated Balance Sheets (Cu

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

Consolidated Balance Sheets (_2

Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized (in shares)	50,000,000	50,000,000
Common shares, outstanding (in shares)	39,729,708	39,664,884
Cumulative Preferred Shares [Member]
Cumulative shares, authorized (in shares)	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0
Cumulative Preference Shares [Member]
Cumulative shares, authorized (in shares)	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0

Consolidated Statements of Inco

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

Consolidated Statements of Comp

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

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)	127,598
Common Stock Issuances, Net of Expenses	$ 638	(638)
Common Stock Retirements (in shares)	(58,495)
Common Stock Retirements	$ (292)	(2,117)			(2,409)
Net Income			26,215		26,215
Other Comprehensive Income (Loss)				(502)	(502)
Employee Stock Incentive Plan Expense		1,146			1,146
Common Dividends			(13,292)		(13,292)
Balance (in shares) at Mar. 31, 2018	39,626,594
Balance at Mar. 31, 2018	$ 198,133	341,841	174,209	(6,133)	708,050
Balance (in shares) at Dec. 31, 2018	39,664,884
Balance at Dec. 31, 2018	$ 198,324	344,250	190,433	(4,144)	728,863
Common Stock Issuances, Net of Expenses (in shares)	120,048
Common Stock Issuances, Net of Expenses	$ 601	(601)
Common Stock Retirements (in shares)	(55,224)
Common Stock Retirements	$ (276)	(2,454)			(2,730)
Net Income			26,324		26,324
Other Comprehensive Income (Loss)				168	168
ASU 2018-02 2017 TCJA Stranded Tax Transfer			784	(784)
Employee Stock Incentive Plan Expense		1,796			1,796
Common Dividends			(13,922)		(13,922)
Balance (in shares) at Mar. 31, 2019	39,729,708
Balance at Mar. 31, 2019	$ 198,649	$ 342,991	$ 203,619	$ (4,760)	$ 740,499

Consolidated Statements of Co_2

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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows from Operating Activities
Net Income	$ 26,324	$ 26,215
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation and Amortization	19,131	18,763
Deferred Tax Credits	(337)	(354)
Deferred Income Taxes	835	2,901
Change in Deferred Debits and Other Assets	1,464	6,295
Discretionary Contribution to Pension Plan	(10,000)	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	8,787	(5,091)
Allowance for Equity/Other Funds Used During Construction	(330)	(638)
Stock Compensation Expense—Equity Awards	1,796	1,146
Other—Net	375	(284)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(37,086)	(25,047)
Change in Inventories	(462)	35
Change in Other Current Assets	128	2,334
Change in Payables and Other Current Liabilities	4,088	(2,798)
Change in Interest and Income Taxes Receivable/Payable	2,437	1,163
Net Cash Provided by Operating Activities	17,150	4,640
Cash Flows from Investing Activities
Capital Expenditures	(24,687)	(23,618)
Net Proceeds from Disposal of Noncurrent Assets	509	510
Cash Used for Investments and Other Assets	(1,258)	(719)
Net Cash Used in Investing Activities	(25,436)	(23,827)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	8	2,338
Net Short-Term Borrowings (Repayments)	25,002	(82,052)
Payments for Retirement of Capital Stock	(2,730)	(2,409)
Proceeds from Issuance of Long-Term Debt		100,000
Short-Term and Long-Term Debt Issuance Expenses		(433)
Payments for Retirement of Long-Term Debt	(42)	(60)
Dividends Paid	(13,922)	(13,292)
Net Cash Provided by Financing Activities	8,316	4,092
Net Change in Cash and Cash Equivalents	30	(15,095)
Cash and Cash Equivalents at Beginning of Period	861	16,216
Cash and Cash Equivalents at End of Period	$ 891	$ 1,121

Note 1 - Summary of Significant

Note 1 - Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Significant Accounting Policies and New Accounting Pronouncements [Text Block]	1. Revenue Recognition Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, 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). These revenues account for over 80% 2. 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) and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2019, 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 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 March 31, 2019 December 31, 2018: March 31, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,444 Corporate Debt Securities – Held by Captive Insurance Company $ 5,975 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,644 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,396 Total Assets $ 2,840 $ 7,619 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 third may Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2019 $53.1 35% Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2019 2018 Finished Goods $ 35,771 $ 37,130 Work in Process 20,503 20,393 Raw Material, Fuel and Supplies 50,458 48,747 Total Inventories $ 106,732 $ 106,270 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 not The following table indicates there were no first three 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) March 31, 2019 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2019 December 31, 2018: March 31, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,410 $ 12,081 9 - 197 Other 154 81 73 17 Total $ 22,645 $ 10,491 $ 12,154 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 4,338 $ 10,451 New Accounting Standards Adopted ASU 2016 02 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 $784,000 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

Note 2 - Business Segment Infor

Note 2 - Business Segment Information	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Segment Reporting Disclosure [Text Block]	2. Segment Information The accounting policies of the segments are described under note 1 three 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 10% 2018, 2018 one 11.2% 2018 one 22.2% 2018 one 11.2% 2018 five 52% 2018 two 39.1% 2018 one All of the Company’s long-lived assets are within the United States and 99.0% 98.3% three March 31, 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 March 31, 2019 2018 March 31, 2019 December 31, 2018 Operating Revenue Three Months Ended March 31, (in thousands) 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 114,955 $ 109,180 Changes in Accrued ARP Revenues (1,049 ) (875 ) Total Retail Sales Revenue 113,906 108,305 Transmission Services Revenue 10,862 11,903 Wholesale Revenues – Company Generation 1,527 1,015 Other Revenues 1,814 1,742 Total Electric Segment Revenues 128,109 122,965 Manufacturing Segment: Metal Parts and Tooling 66,724 56,927 Plastic Products and Tooling 9,045 10,235 Other 2,053 1,500 Total Manufacturing Segment Revenues 77,822 68,662 Plastics Segment – Sale of PVC Pipe Products 40,058 49,653 Intersegment Eliminations (17 ) (14 ) Total $ 245,972 $ 241,266 Interest Charges Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 6,641 $ 6,390 Manufacturing 584 554 Plastics 149 150 Corporate and Intersegment Eliminations 452 278 Total $ 7,826 $ 7,372 Income Taxes Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 4,771 $ 2,098 Manufacturing 1,454 1,223 Plastics 1,329 2,414 Corporate (1,926 ) (1,941 ) Total $ 5,628 $ 3,794 Net Income (Loss) Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 18,700 $ 16,668 Manufacturing 4,842 4,164 Plastics 3,729 6,844 Corporate (947 ) (1,461 ) Total $ 26,324 $ 26,215 Identifiable Assets March 31, December 31, (in thousands) 2019 2018 Electric $ 1,737,278 $ 1,728,534 Manufacturing 217,390 187,556 Plastics 104,544 91,630 Corporate 45,336 44,797 Total $ 2,104,548 $ 2,052,517

Note 3 - Rate and Regulatory Ma

Note 3 - Rate and Regulatory Matters	3 Months Ended
	Mar. 31, 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 245 2021. November 3, 2017, August 3, 2018 September 26, 2018 December 2018 January 2019. March 31, 2019, $7.7 Merricourt Project November 16, 2016 150 $34.7 November 16, 2016, 2020 $200.5 October 26, 2017 January 10, 2018. November 3, 2017. April 2019. 2019. March 31, 2019, $5.3 Big Stone South–Ellendale Multi-Value Transmission Project (MVP) 345 February 6, 2019, 163 December 2011. March 31, 2019 $106 100% Recovery of OTP’s major transmission investments is through the MISO Tariff and, currently, Minnesota, North Dakota and South Dakota base rates and TCR riders. Minnesota General Rates 2016 March 2017 May 1, 2017. 8.61% 10.74%. The MPUC’s order also included: ( 1 2 November 1, 2017. Minnesota Conservation Improvement Programs (MNCIP) not May 25, 2016 13.5% 2017 12% 2018 10% 2019 1.7% 40% 2017 35% 2018 30% 2019 50% March 20, 2019 2017 2019 one 2020.   On April 1, 2019 2018 $3.0 2018 not 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, March 31, 2019 $2.5 Environmental Cost Recovery Rider 2010 2016 November 2017. 2018 zero December 1, 2018. March April 2019. Renewable Resource Adjustment November 1, 2017, 2017 2018. North Dakota General Rates November 2, 2017 $13.1 8.72%. $13.1 7.97% 10.3%. December 20, 2017 $12.8 January 1, 2018. February 27, 2018 $4.5 $8.3 March 1, 2018. On March 23, 2018 $13.1 $7.1 4.8% $6.0 $4.8 $1.2 In a September 26, 2018 $4.6 3.1% 9.77% 52.5% March 2018 $7.1 4.8% 10.3%. not February 1, 2019, April 2019 $3.4 March 31, 2019, $0.8 January February 2018. Renewable Resource Adjustment Effective in February 2019 2017 Transmission Cost Recovery Rider 2017 26 26A 2017 Environmental Cost Recovery Rider 2017 February 1, 2019, February 1, 2019 Generation Cost Recovery Rider March 1, 2019 South Dakota General Rate s April 20, 2018 $3.3 10.1%, first two October 18, 2018. second 1.7% The SDPUC approved a partial settlement on March 1, 2019 second January 1, 2018 October 17, 2018 $1.0 first 2019. second 2019. OTP’s previously approved general rate increase in South Dakota of approximately $643,000 2.32% April 2011 June 2011. 8.50%. 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 8, 2019 March 1, 2019. January 1, 2019 January 2020. Environmental Cost Recovery Rider October 18, 2018 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 R – April 1, 2019 October 1, 2019 $ 11,926 $0.00710/kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base Transmission Cost Recovery 2018 Supplemental Update A – December 6, 2018 February 1, 2019 $ 4,801 Various 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various Environmental Cost Recovery 2018 Update A – December 19, 2018 February 1, 2019 $ (378 ) -0.310% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base Generation Cost Recovery 2019 Initial Request R – March 1, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2019 Annual Update A – February 20, 2019 March 1, 2019 $ 1,638 Various 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075/kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three March 31: Rate Rider (in thousands) 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,152 $ 2,516 Renewable Resource Recovery 1,316 525 Transmission Cost Recovery 641 (29 ) Environmental Cost Recovery (1 ) (31 ) North Dakota Transmission Cost Recovery 1,772 2,062 Renewable Resource Adjustment 729 1,967 Environmental Cost Recovery 575 1,821 Generation Cost Recovery 248 -- South Dakota Transmission Cost Recovery 473 536 Conservation Improvement Program Costs and Incentives 244 229 Environmental Cost Recovery (4 ) 520 Total $ 8,145 $ 10,116 1 Includes MNCIP costs recovered in base rates. TCJA The TCJA, passed in December 2017, 35% 21%, January 1, 2018. 35% 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 second 2019 one third 2019, January 3, 2019 As described above, OTP’s current general rate cases in North Dakota and South Dakota reflect the ongoing impact of the TCJA in interim rates. OTP has accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurs under the lower federal tax rates in the TCJA. As of March 31, 2019, $10.4 $0.8 January February 2018, $0.3 April 2019. As of 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 On November 12, 2013 may 12.38% 9.15%. 15 November 12, 2013 February 11, 2015. December 22, 2015 10.32%, September 28, 2016 10.32%. September 2016 On November 6, 2014 50 January 5, 2015 November 12, 2013 10.82% 10.32% 0.5% September 28, 2016. On February 12, 2015 may 12.38% 8.67%. second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 9.7%. second Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 December 31, 2016, first 15 February June 2017 2016 $2.7 December 31, 2016 $1.6 March 31, 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. 10.41%, 13.08% 206 November 15, 2018, two February 13, 2019 April 10, 2019. no third fourth 2019. OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 March 31, 2019 second

Note 4 - Regulatory Assets and

Note 4 - Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Schedule of Regulatory Assets and Liabilities [Text Block]	4. As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC 980. 980 605 25 March 31, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 116,835 $ 123,190 see below Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,302 7,302 asset lives Conservation Improvement Program Costs and Incentives 2 3,007 3,979 6,986 18 Deferred Marked-to-Market Losses 1 1,432 557 1,989 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 1,958 -- 1,958 12 Deferred Income Taxes 1 -- 1,557 1,557 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 689 770 1,459 25 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 1,143 1,143 asset lives Debt Reacquisition Premiums 1 203 701 904 162 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 416 -- 416 12 Big Stone II Unrecovered Project Costs – South Dakota 1 117 292 409 42 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 180 130 310 33 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 248 -- 248 12 Recoverable Fuel and Purchased Power Costs – South Dakota 1 197 -- 197 12 Minnesota SPP Transmission Cost Recovery Tracker 1 -- 117 117 see below Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 52 -- 52 4 Deferred Lease Expenses 1 -- 44 44 48 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 38 -- 38 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 34 -- 34 12 Total Regulatory Assets $ 15,193 $ 133,427 $ 148,620 Regulatory Liabilities: Deferred Income Taxes $ -- $ 141,452 $ 141,452 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,555 83,555 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 5,149 -- 5,149 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 901 -- 901 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 669 -- 669 12 Refundable Fuel Clause Adjustment Revenues – North Dakota 537 -- 537 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 272 -- 272 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 225 225 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up -- 187 187 21 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 103 -- 103 12 Other 5 77 82 177 Total Regulatory Liabilities $ 7,787 $ 225,496 $ 233,283 Net Regulatory Asset/(Liability) Position $ 7,406 $ (92,069 ) $ (84,663 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 -- 444 12 Deferred Income Taxes 1 -- 2,423 2,423 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 986 986 asset lives Debt Reacquisition Premiums 1 207 753 960 165 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 -- 455 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 -- 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 -- 178 12 Minnesota SPP Transmission Cost Recovery Tracker 1 -- 176 176 see below Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 -- 328 4 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 -- 121 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 -- 452 12 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 -- 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ -- $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,229 83,229 asset lives North Dakota Renewable Resource Recovery Rider Accrued Refund 177 -- 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 -- 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up -- 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 -- 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 -- 207 12 Refundable Fuel Clause Adjustment Revenues 121 -- 121 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. All Deferred Marked-to-Market Losses recorded as of March 31, 2019 December 2020. The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of March 31, 2019. The regulatory asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 162 North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. MISO Schedule 26/26A 26/26A South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018. North Dakota Generation Cost Recovery (NDGCR) Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The March 31, 2019 not July 2019 The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not March 31, 2019. Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers. Deferred Lease Expenses: Under ASC 842 March 31, 2019 The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are recoverable from Minnesota customers as of March 31, 2019. The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of March 31, 2019. base rates related to the expiration of the PTCs. Recovery will continue through the rider until interim or revised base rates are established in connection with OTP’s next Minnesota rate case. North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that are recoverable from North Dakota customers as of March 31, 2019. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2019. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of March 31, 2019. February 1, 2019 The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2019. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred. The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2019. The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2019. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980

Note 5 - Common Shares and Earn

Note 5 - Common Shares and Earnings Per Share	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Stockholders Equity and Earnings per Share [Text Block]	5. 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 March 31, 2019: Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 17,850 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, March 31, 2019 39,729,708 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three March 31, 2019 2018. not three March 31: 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,657,321 39,550,874 Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance 158,159 223,162 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 63,398 59,130 Nonvested Restricted Shares 21,922 27,643 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,365 2,873 Total Dilutive Shares 245,844 312,808 Weighted Average Common Shares Outstanding – Diluted 39,903,165 39,863,682 The effect of dilutive shares on earnings per share for the three March 31, 2019 2018, no $0.01

Note 6 - Share-based Payments

Note 6 - Share-based Payments	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Share-based Payment Arrangement [Text Block]	6. Stock Incentive Awards On February 13, 2019 2014 Award Shares/Units Granted Weighted Average Grant- Date Fair Value per Award Vesting Restricted Stock Units Granted 15,600 $ 49.6225 25% per year through February 6, 2023 Stock Performance Awards Granted: Under Executive and Select Employee Agreements 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement 7,800 $ 45.885 December 31, 2021 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant. Under the performance share awards the aggregate award for performance at target is 55,600 27,800 3 27,800 January 1, 2019 December 31, 2021, 20 January 1, 2019 20 January 1, 2022. may zero 150% 83,400 no 718, Compensation – Stock Compensation Under the 2019 The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of March 31, 2019, $6.2 2.2 Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three March 31, 2019 2018 Three months ended March 31, (in thousands) 2019 2018 Stock Performance Awards Granted to Executive Officers $ 1,113 $ 651 Restricted Stock Units Granted to Executive Officers 427 249 Restricted Stock Granted to Executive Officers -- 16 Restricted Stock Granted to Directors 165 166 Restricted Stock Units Granted to Non-Executive Employees 91 64 Totals $ 1,796 $ 1, 146

Note 7 - Retained Earnings and

Note 7 - Retained Earnings and Dividend Restriction	3 Months Ended
	Mar. 31, 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 March 31, 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 47.9% 58.5% 2018 October 18, 2018. March 31, 2019, 53.2% $484 $1.2

Note 8 - Leases

Note 8 - Leases	3 Months Ended
	Mar. 31, 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 10 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 March 31, 2019 (in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,421 $ 16,976 $ 666 $ 767 $ 21,830 Accumulated Amortization (257 ) (734 ) (97 ) (30 ) (1,118 ) Net of Accumulated Amortization $ 3,164 $ 16,242 $ 569 $ 737 $ 20,712 Obligations: Current Operating Lease Liabilities $ 913 $ 2,458 $ 379 $ 150 $ 3,900 Long-Term Operating Lease Liabilities 2,470 13,852 190 648 17,160 Total Lease Liabilities $ 3,383 $ 16,310 $ 569 $ 798 $ 21,060 The amounts of the Company’s right-of-use operating lease obligations for each of the five 2019 2023 2023 not March 31, 2019. Right-of-Use Operating Leases (in thousands) OTP Nonelectric Total 2019 $ 845 $ 3,078 $ 3,923 2020 1,115 3,948 5,063 2021 1,091 3,657 4,748 2022 207 3,529 3,736 2023 196 3,209 3,405 Beyond 2023 447 8,023 8,470 Total Minimum Obligations $ 3,901 $ 25,443 $ 29,344 Interest Component of Obligations (355 ) (4,376 ) (4,731 ) Present Value of Leases Commencing after March 31, 2019 (163 ) (3,390 ) (3,553 ) Present Value of Minimum Obligations, March 31, 2019 $ 3,383 $ 17,677 $ 21,060 The Company’s total minimum lease obligations reported in the table above include obligations for a ten 2018 July 2019 27 20 April 2019. The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 6 5.0%. A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 January 1, 2019 March 31, 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 -- 1,725 1,725 Lease Obligation Payments (270 ) (1,020 ) (1,290 ) Interest Component of Lease Obligation Payment 44 212 256 Operating Lease Obligations, March 31, 2019 $ 3,383 $ 17,677 $ 21,060 OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income. The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the three March 31, 2019 (in thousands) Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ -- $ 9 Inventory 225 -- 225 Cost of Products Sold 1,036 27 1,063 Electric Operation and Maintenance Expenses 66 -- 66 Other Nonelectric Expenses 54 -- 54 Total $ 1,390 $ 27 $ 1,417

Note 9 - Commitments and Contin

Note 9 - Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	9. Construction and Other Purchase Commitments At March 31, 2019 2021 $70.5 December 31, 2018 2021 $64.5 March 31, 2019 December 31, 2021 $4.7 December 31, 2018 December 31, 2021 $5.0 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. 2040. 2020. December 31, 2020. no 2019 December 31, 2023. no OTP Land Easements OTP has commitments to make future payments for land easements not 2034 $10.8 Contingencies OTP had a $1.6 March 31, 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. The Company currently is not In 2015 111 not 2016. 2017, April 2018. On August 21, 2018 not three Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2019 not

Note 10 - Short-term and Long-t

Note 10 - Short-term and Long-term Borrowings	3 Months Ended
	Mar. 31, 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 March 31, 2019 December 31, 2018: (in thousands) Line Limit In Use on March 31, 2019 Restricted due to Outstanding Letters of Credit Available on March 31, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 27,742 $ -- $ 102,258 $ 120,785 OTP Credit Agreement 170,000 15,859 300 153,841 160,316 Total $ 300,000 $ 43,601 $ 300 $ 256,099 $ 281,101 The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2019 December 31, 2018: March 31, 201 9 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 15,859 $ 27,742 $ 43,601 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 480 480 Total $ 512,000 $ 80,480 $ 592,480 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 174 174 Unamortized Long-Term Debt Issuance Costs 1,890 394 2,284 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,110 $ 79,912 $ 590,022 Total Short-Term and Long-Term Debt (with current maturities) $ 525,969 $ 107,828 $ 633,797 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773

Note 11 - Pension Plan and Othe

Note 11 - Pension Plan and Other Postretirement Benefits	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Pension and Other Postretirement Benefits Disclosure [Text Block]	1 1 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 Interest Cost on Projected Benefit Obligation 3,603 3,363 Expected Return on Assets (5,325 ) (5,300 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 From Other Comprehensive Income 1 2 -- Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 From Other Comprehensive Income 1 27 44 Net Periodic Pension Cost 2 $ 844 $ 1,510 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs: Service c osts included in OTP c apital e xpenditures $ 390 $ 328 Service c osts included in e lectric o peration and m aintenance e xpenses 950 1,247 Service c osts included in o ther n onelectric e xpenses 33 40 Nonservice costs capitalized as regulatory assets (150 ) (21 ) Nonservice costs included in n onservice cost components of postretirement benefits (379 ) (84 ) Cash flows no December 31, 2018 $10 January 2019. Executive Survivor and Supplemental Retirement Plan Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 105 $ 100 Interest Cost on Projected Benefit Obligation 434 399 Amortization of Prior Service Cost: From Regulatory Asset 1 4 From Other Comprehensive Income 1 4 10 Amortization of Net Actuarial Loss: From Regulatory Asset 31 67 From Other Comprehensive Income 1 87 165 Net Periodic Pension Cost 2 $ 662 $ 745 1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice cost components of postretirement benefits . 2 Allocation of Costs: Service c osts included in e lectric o peration and m aintenance e xpenses $ 26 $ 25 Service costs included in ot her n onelectric e xpenses 79 75 Nonservice c osts included in n onservice cost components of postretirement benefits 557 645 Other Postretirement Benefits Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 Interest Cost on Projected Benefit Obligation 770 645 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 From Other Comprehensive Income 1 10 10 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,449 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Service c osts included in OTP capital expenditures $ 91 $ 78 Service costs included in electric operation and maintenance expenses 223 294 Service costs included in other nonelectric expenses 7 10 Nonservice costs capitalized as regulatory assets 333 217 Nonservice costs included in n onservice cost components of postretirement benefits 840 850

Note 12 - Fair Value of Financi

Note 12 - Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Fair Value Disclosures [Text Block]	1 2 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt March 31, 2019 December 31, 2018 1.50% 1.25% Long-Term Debt including Current Maturities 2 820. March 31, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 891 $ 891 $ 861 $ 861 Short-Term Debt (43,601 ) (43,601 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,196 ) (611,219 ) (590,174 ) (601,513 )

Note 13 - Property, Plant and E

Note 13 - Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Property, Plant and Equipment Disclosure [Text Block]	13. No

Note 14 - Income Tax Expense -

Note 14 - Income Tax Expense - Continuing Operations	3 Months Ended
	Mar. 31, 2019
Notes to Financial Statements
Income Tax Disclosure [Text Block]	1 4 . Income Tax Expense The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three March 31, 2019 2018: Three Months Ended March 31, (in thousands) 2019 2018 Income Before Income Taxes $ 31,952 $ 30,009 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) 8,308 7,802 Increases (Decreases) in Tax from: Differences Reversing in Excess of Federal Rates (983 ) (1,073 ) Excess Tax Deduction – Equity Method Stock Awards (827 ) (624 ) Corporate Owned Life Insurance (409 ) (8 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) Research and Development and Other Tax Credits (188 ) (180 ) Allowance for Funds Used During Construction – Equity (86 ) (167 ) Federal Production Tax Credits (PTCs) -- (1,120 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- (531 ) Other Items – Net 71 (47 ) Income Tax Expense $ 5,628 $ 3,794 Effective Income Tax Rate 17.6 % 12.6 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Current Year 38 36 Uncertain Positions Resolved During Year -- (44 ) Balance on March 31 $ 1,320 $ 676 The balance of unrecognized tax benefits as of March 31, 2019 March 31, 2019 not 12 no March 31, 2019. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of May 1, 2019, no 2015

Significant Accounting Policies

Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Revenue [Policy Text Block]	Revenue Recognition Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, 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). These revenues account for over 80% 2. 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) and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2019, 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 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 March 31, 2019 December 31, 2018: March 31, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,444 Corporate Debt Securities – Held by Captive Insurance Company $ 5,975 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,644 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,396 Total Assets $ 2,840 $ 7,619 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 third may
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2019 $53.1 35%
Inventory, Policy [Policy Text Block]	Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2019 2018 Finished Goods $ 35,771 $ 37,130 Work in Process 20,503 20,393 Raw Material, Fuel and Supplies 50,458 48,747 Total Inventories $ 106,732 $ 106,270
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 not The following table indicates there were no first three 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) March 31, 2019 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2019 December 31, 2018: March 31, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,410 $ 12,081 9 - 197 Other 154 81 73 17 Total $ 22,645 $ 10,491 $ 12,154 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099
Cash Flow Supplemental [Policy Text Block]	Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 4,338 $ 10,451
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Standards Adopted ASU 2016 02 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 $784,000 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

Note 1 - Summary of Significa_2

Note 1 - Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	March 31, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,444 Corporate Debt Securities – Held by Captive Insurance Company $ 5,975 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,644 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,396 Total Assets $ 2,840 $ 7,619 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484
Schedule of Inventory, Current [Table Text Block]	March 31, December 31, (in thousands) 2019 2018 Finished Goods $ 35,771 $ 37,130 Work in Process 20,503 20,393 Raw Material, Fuel and Supplies 50,458 48,747 Total Inventories $ 106,732 $ 106,270
Schedule of Goodwill [Table Text Block]	(in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) March 31, 2019 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572
Schedule of Finite-Lived Intangible Assets [Table Text Block]	March 31, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,410 $ 12,081 9 - 197 Other 154 81 73 17 Total $ 22,645 $ 10,491 $ 12,154 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	Three Months Ended March 31, (in thousands) 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	(in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	As of March 31, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 4,338 $ 10,451
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	(in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 )

Note 2 - Business Segment Inf_2

Note 2 - Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended March 31, (in thousands) 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 114,955 $ 109,180 Changes in Accrued ARP Revenues (1,049 ) (875 ) Total Retail Sales Revenue 113,906 108,305 Transmission Services Revenue 10,862 11,903 Wholesale Revenues – Company Generation 1,527 1,015 Other Revenues 1,814 1,742 Total Electric Segment Revenues 128,109 122,965 Manufacturing Segment: Metal Parts and Tooling 66,724 56,927 Plastic Products and Tooling 9,045 10,235 Other 2,053 1,500 Total Manufacturing Segment Revenues 77,822 68,662 Plastics Segment – Sale of PVC Pipe Products 40,058 49,653 Intersegment Eliminations (17 ) (14 ) Total $ 245,972 $ 241,266 Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 6,641 $ 6,390 Manufacturing 584 554 Plastics 149 150 Corporate and Intersegment Eliminations 452 278 Total $ 7,826 $ 7,372 Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 4,771 $ 2,098 Manufacturing 1,454 1,223 Plastics 1,329 2,414 Corporate (1,926 ) (1,941 ) Total $ 5,628 $ 3,794 Three Months Ended March 31, (in thousands) 2019 2018 Electric $ 18,700 $ 16,668 Manufacturing 4,842 4,164 Plastics 3,729 6,844 Corporate (947 ) (1,461 ) Total $ 26,324 $ 26,215 March 31, December 31, (in thousands) 2019 2018 Electric $ 1,737,278 $ 1,728,534 Manufacturing 217,390 187,556 Plastics 104,544 91,630 Corporate 45,336 44,797 Total $ 2,104,548 $ 2,052,517

Note 3 - Rate and Regulatory _2

Note 3 - Rate and Regulatory Matters (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Information on Status of Updates for Previous Periods [Table Text Block]	Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2018 Incentive and Cost Recovery R – April 1, 2019 October 1, 2019 $ 11,926 $0.00710/kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base Transmission Cost Recovery 2018 Supplemental Update A – December 6, 2018 February 1, 2019 $ 4,801 Various 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various Environmental Cost Recovery 2018 Update A – December 19, 2018 February 1, 2019 $ (378 ) -0.310% of base 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base Generation Cost Recovery 2019 Initial Request R – March 1, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2019 Annual Update A – February 20, 2019 March 1, 2019 $ 1,638 Various 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075/kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh
Schedule of Revenues Recorded under Rate Riders [Table Text Block]	Rate Rider (in thousands) 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,152 $ 2,516 Renewable Resource Recovery 1,316 525 Transmission Cost Recovery 641 (29 ) Environmental Cost Recovery (1 ) (31 ) North Dakota Transmission Cost Recovery 1,772 2,062 Renewable Resource Adjustment 729 1,967 Environmental Cost Recovery 575 1,821 Generation Cost Recovery 248 -- South Dakota Transmission Cost Recovery 473 536 Conservation Improvement Program Costs and Incentives 244 229 Environmental Cost Recovery (4 ) 520 Total $ 8,145 $ 10,116

Note 4 - Regulatory Assets an_2

Note 4 - Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Regulatory Assets and Liabilities [Table Text Block]	March 31, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 116,835 $ 123,190 see below Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,302 7,302 asset lives Conservation Improvement Program Costs and Incentives 2 3,007 3,979 6,986 18 Deferred Marked-to-Market Losses 1 1,432 557 1,989 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 1,958 -- 1,958 12 Deferred Income Taxes 1 -- 1,557 1,557 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 689 770 1,459 25 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 1,143 1,143 asset lives Debt Reacquisition Premiums 1 203 701 904 162 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 416 -- 416 12 Big Stone II Unrecovered Project Costs – South Dakota 1 117 292 409 42 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 180 130 310 33 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 248 -- 248 12 Recoverable Fuel and Purchased Power Costs – South Dakota 1 197 -- 197 12 Minnesota SPP Transmission Cost Recovery Tracker 1 -- 117 117 see below Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 52 -- 52 4 Deferred Lease Expenses 1 -- 44 44 48 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 38 -- 38 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 34 -- 34 12 Total Regulatory Assets $ 15,193 $ 133,427 $ 148,620 Regulatory Liabilities: Deferred Income Taxes $ -- $ 141,452 $ 141,452 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,555 83,555 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 5,149 -- 5,149 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 901 -- 901 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 669 -- 669 12 Refundable Fuel Clause Adjustment Revenues – North Dakota 537 -- 537 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 272 -- 272 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 225 225 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up -- 187 187 21 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 103 -- 103 12 Other 5 77 82 177 Total Regulatory Liabilities $ 7,787 $ 225,496 $ 233,283 Net Regulatory Asset/(Liability) Position $ 7,406 $ (92,069 ) $ (84,663 ) December 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 -- 444 12 Deferred Income Taxes 1 -- 2,423 2,423 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 986 986 asset lives Debt Reacquisition Premiums 1 207 753 960 165 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 -- 455 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 -- 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 -- 178 12 Minnesota SPP Transmission Cost Recovery Tracker 1 -- 176 176 see below Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 -- 328 4 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 -- 121 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 -- 452 12 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 -- 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ -- $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,229 83,229 asset lives North Dakota Renewable Resource Recovery Rider Accrued Refund 177 -- 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 -- 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up -- 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 -- 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 -- 207 12 Refundable Fuel Clause Adjustment Revenues 121 -- 121 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 )

Note 5 - Common Shares and Ea_2

Note 5 - Common Shares and Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 17,850 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, March 31, 2019 39,729,708
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	2019 2018 Weighted Average Common Shares Outstanding – Basic 39,657,321 39,550,874 Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance 158,159 223,162 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 63,398 59,130 Nonvested Restricted Shares 21,922 27,643 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,365 2,873 Total Dilutive Shares 245,844 312,808 Weighted Average Common Shares Outstanding – Diluted 39,903,165 39,863,682

Note 6 - Share-based Payments (

Note 6 - Share-based Payments (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	Award Shares/Units Granted Weighted Average Grant- Date Fair Value per Award Vesting Restricted Stock Units Granted 15,600 $ 49.6225 25% per year through February 6, 2023 Stock Performance Awards Granted: Under Executive and Select Employee Agreements 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement 7,800 $ 45.885 December 31, 2021
Share-based Payment Arrangement, Activity [Table Text Block]	Three months ended March 31, (in thousands) 2019 2018 Stock Performance Awards Granted to Executive Officers $ 1,113 $ 651 Restricted Stock Units Granted to Executive Officers 427 249 Restricted Stock Granted to Executive Officers -- 16 Restricted Stock Granted to Directors 165 166 Restricted Stock Units Granted to Non-Executive Employees 91 64 Totals $ 1,796 $ 1, 146

Note 8 - Leases (Tables)

Note 8 - Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Leases, Right-of-use Assets and Lease Liabilities By Business Segment [Table Text Block]	(in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,421 $ 16,976 $ 666 $ 767 $ 21,830 Accumulated Amortization (257 ) (734 ) (97 ) (30 ) (1,118 ) Net of Accumulated Amortization $ 3,164 $ 16,242 $ 569 $ 737 $ 20,712 Obligations: Current Operating Lease Liabilities $ 913 $ 2,458 $ 379 $ 150 $ 3,900 Long-Term Operating Lease Liabilities 2,470 13,852 190 648 17,160 Total Lease Liabilities $ 3,383 $ 16,310 $ 569 $ 798 $ 21,060
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Right-of-Use Operating Leases (in thousands) OTP Nonelectric Total 2019 $ 845 $ 3,078 $ 3,923 2020 1,115 3,948 5,063 2021 1,091 3,657 4,748 2022 207 3,529 3,736 2023 196 3,209 3,405 Beyond 2023 447 8,023 8,470 Total Minimum Obligations $ 3,901 $ 25,443 $ 29,344 Interest Component of Obligations (355 ) (4,376 ) (4,731 ) Present Value of Leases Commencing after March 31, 2019 (163 ) (3,390 ) (3,553 ) Present Value of Minimum Obligations, March 31, 2019 $ 3,383 $ 17,677 $ 21,060
Lessee, Operating Lease, Lease Obligation Activity [Table Text Block]	(in thousands) OTP Nonelectric Total Operating Lease Obligations, January 1, 2019 $ 3,609 $ 16,760 $ 20,369 Non-cash Acquisition of Right-of-Use Assets -- 1,725 1,725 Lease Obligation Payments (270 ) (1,020 ) (1,290 ) Interest Component of Lease Obligation Payment 44 212 256 Operating Lease Obligations, March 31, 2019 $ 3,383 $ 17,677 $ 21,060
Lease, Cost [Table Text Block]	(in thousands) Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ -- $ 9 Inventory 225 -- 225 Cost of Products Sold 1,036 27 1,063 Electric Operation and Maintenance Expenses 66 -- 66 Other Nonelectric Expenses 54 -- 54 Total $ 1,390 $ 27 $ 1,417

Note 10 - Short-term and Long_2

Note 10 - Short-term and Long-term Borrowings (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Line of Credit Facilities [Table Text Block]	(in thousands) Line Limit In Use on March 31, 2019 Restricted due to Outstanding Letters of Credit Available on March 31, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 27,742 $ -- $ 102,258 $ 120,785 OTP Credit Agreement 170,000 15,859 300 153,841 160,316 Total $ 300,000 $ 43,601 $ 300 $ 256,099 $ 281,101
Schedule of Debt [Table Text Block]	March 31, 201 9 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 15,859 $ 27,742 $ 43,601 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 480 480 Total $ 512,000 $ 80,480 $ 592,480 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 174 174 Unamortized Long-Term Debt Issuance Costs 1,890 394 2,284 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,110 $ 79,912 $ 590,022 Total Short-Term and Long-Term Debt (with current maturities) $ 525,969 $ 107,828 $ 633,797 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773

Note 11 - Pension Plan and Ot_2

Note 11 - Pension Plan and Other Postretirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 Interest Cost on Projected Benefit Obligation 3,603 3,363 Expected Return on Assets (5,325 ) (5,300 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 From Other Comprehensive Income 1 2 -- Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 From Other Comprehensive Income 1 27 44 Net Periodic Pension Cost 2 $ 844 $ 1,510 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs: Service c osts included in OTP c apital e xpenditures $ 390 $ 328 Service c osts included in e lectric o peration and m aintenance e xpenses 950 1,247 Service c osts included in o ther n onelectric e xpenses 33 40 Nonservice costs capitalized as regulatory assets (150 ) (21 ) Nonservice costs included in n onservice cost components of postretirement benefits (379 ) (84 ) Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 105 $ 100 Interest Cost on Projected Benefit Obligation 434 399 Amortization of Prior Service Cost: From Regulatory Asset 1 4 From Other Comprehensive Income 1 4 10 Amortization of Net Actuarial Loss: From Regulatory Asset 31 67 From Other Comprehensive Income 1 87 165 Net Periodic Pension Cost 2 $ 662 $ 745 1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice cost components of postretirement benefits . 2 Allocation of Costs: Service c osts included in e lectric o peration and m aintenance e xpenses $ 26 $ 25 Service costs included in ot her n onelectric e xpenses 79 75 Nonservice c osts included in n onservice cost components of postretirement benefits 557 645 Three Months Ended March 31, (in thousands) 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 Interest Cost on Projected Benefit Obligation 770 645 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 From Other Comprehensive Income 1 10 10 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,449 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Service c osts included in OTP capital expenditures $ 91 $ 78 Service costs included in electric operation and maintenance expenses 223 294 Service costs included in other nonelectric expenses 7 10 Nonservice costs capitalized as regulatory assets 333 217 Nonservice costs included in n onservice cost components of postretirement benefits 840 850

Note 12 - Fair Value of Finan_2

Note 12 - Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Fair Value, by Balance Sheet Grouping [Table Text Block]	March 31, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 891 $ 891 $ 861 $ 861 Short-Term Debt (43,601 ) (43,601 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,196 ) (611,219 ) (590,174 ) (601,513 )

Note 14 - Income Tax Expense _2

Note 14 - Income Tax Expense - Continuing Operations (Tables)	3 Months Ended
	Mar. 31, 2019
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Three Months Ended March 31, (in thousands) 2019 2018 Income Before Income Taxes $ 31,952 $ 30,009 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) 8,308 7,802 Increases (Decreases) in Tax from: Differences Reversing in Excess of Federal Rates (983 ) (1,073 ) Excess Tax Deduction – Equity Method Stock Awards (827 ) (624 ) Corporate Owned Life Insurance (409 ) (8 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) Research and Development and Other Tax Credits (188 ) (180 ) Allowance for Funds Used During Construction – Equity (86 ) (167 ) Federal Production Tax Credits (PTCs) -- (1,120 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- (531 ) Other Items – Net 71 (47 ) Income Tax Expense $ 5,628 $ 3,794 Effective Income Tax Rate 17.6 % 12.6 %
Summary of Income Tax Contingencies [Table Text Block]	(in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Current Year 38 36 Uncertain Positions Resolved During Year -- (44 ) Balance on March 31 $ 1,320 $ 676

Note 1 - Summary of Significa_3

Note 1 - Summary of Significant Accounting Policies (Details Textual) - USD ($)	Jan. 01, 2019	Mar. 31, 2019	Mar. 31, 2018
Goodwill, Impairment Loss			$ 0
Goodwill, Period Increase (Decrease), Total		$ 0
Accounting Standards Update 2018-02 [Member]
Tax Cuts and Jobs Act, Reclassification of Stranded Tax Effect From AOCI to Retained Earnings	$ 784,000
Coyote Creek Mining Company, L.L.C. (CCMC) [Member] | Otter Tail Power Company [Member] | Lignite Sales Agreement [Member]
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount		$ 53,100,000
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage		35.00%

Note 1 - Summary of Significa_4

Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 1 [Member]
Assets:
Total Assets	$ 2,840	$ 2,132
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets:
Investments	1,444	1,294
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets	1,396	838
Fair Value, Inputs, Level 2 [Member]
Assets:
Total Assets	7,619	7,484
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets:
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Assets:
Investments	5,975	5,898
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments	1,644	$ 1,586
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets

Note 1 - Summary of Significa_5

Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Finished Goods	$ 35,771	$ 37,130
Work in Process	20,503	20,393
Raw Material, Fuel and Supplies	50,458	48,747
Total Inventories	$ 106,732	$ 106,270

Note 1 - Summary of Significa_6

Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Gross Balance		$ 37,572,000
Accumulated Impairments
Balance	$ 37,572,000	37,572,000
Adjustments to Goodwill	0
Manufacturing [Member]
Gross Balance		18,270,000
Accumulated Impairments
Balance	18,270,000	18,270,000
Adjustments to Goodwill
Plastics [Member]
Gross Balance		19,302,000
Accumulated Impairments
Balance	19,302,000	$ 19,302,000
Adjustments to Goodwill

Note 1 - Summary of Significa_7

Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Gross Carrying Amount	$ 22,645	$ 22,645
Accumulated Amortization	10,491	10,195
Net Carrying Amount	12,154	12,450
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	10,410	10,127
Net Carrying Amount	$ 12,081	$ 12,364
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	270 days	1 year
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	16 years 150 days	16 years 240 days
Other Intangible Assets [Member]
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	81	68
Net Carrying Amount	$ 73	$ 86
Remaining Amortization Periods (Month)	1 year 150 days	1 year 240 days

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
	Mar. 31, 2019	Mar. 31, 2018
Amortization Expense – Intangible Assets	$ 296	$ 345

Note 1 - Summary of Significa_9

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

Note 1 - Summary of Signific_11

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

Note 2 - Business Segment Inf_3

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

Note 2 - Business Segment Inf_4

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

Note 3 - Rate and Regulatory _3

Note 3 - Rate and Regulatory Matters (Details Textual)	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. 01, 2011USD ($)	Jun. 30, 2016	Dec. 22, 2015	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017	Mar. 01, 2018USD ($)	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																	$ 233,283,000	$ 227,207,000
MONTANA
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	10,400,000
NORTH DAKOTA
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	800,000
Federal Energy Regulatory Commission [Member]
Accrued Refund Liabilities Resulting from Tax Rate Reduction																	300,000
Otter Tail Power Company [Member] | Litigation Case with Minnesota Customers [Member]
Loss Contingency, Estimate of Possible Loss																	2,500,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Current Return on Equity Used in Transmission Rates									10.32%				12.38%			10.32%
Proposed Reduced Return on Equity Used in Transmission Rates											8.67%		9.15%		9.70%
Additional Incentive Basis Point												0.50%
Expected Percentage of Return on Equity			10.41%						10.82%
Regulatory Liabilities, Total																		$ 1,600,000						$ 2,700,000
Contract with Customer, Refund Liability, Total																	1,600,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | Maximum [Member]
Proposed Reduced Return on Equity Used in Transmission Rates			13.08%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																							8.61%
Percentage of Allowed Rate of Return on Equity																							10.74%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member]
Utility Incentive Percentage in Next Rolling Twelve Months										13.50%
Utility Incentive Percentage in Next Rolling Year Two										12.00%
Utility Incentive Percentage in Next Rolling Year Three										10.00%
Assumed Savings of Utility										1.70%
Financial Incentive, Maximum Percentage of Spending, Year One										40.00%
Financial Incentive, Maximum Percentage of Spending, Year Two										35.00%
Financial Incentive, Maximum Percentage of Spending, Year Three										30.00%
Expected Rate of Financial Incentive Reduction										50.00%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member]
Financial Incentives Recognized During Period	$ 3,000,000
Otter Tail Power Company [Member] | MONTANA
Environmental Cost Recovery Rider Rate		0.00%
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base																						7.97%
Percentage of Allowed Rate of Return on Equity																						10.30%
General Rate Revenue Increase Requested																					$ 12,800,000	$ 13,100,000
Percentage of Increase in Base Rate Revenue Requested																						8.72%
Public Utilities, Interim Rate Requirement, Decrease in Amount																				$ 4,500,000
Public Utilities, Interim Rate Requirement, Amount																				$ 8,300,000
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member]
Percentage of Allowed Rate of Return on Equity						10.30%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 4,600,000		$ 7,100,000	$ 13,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage				3.10%		4.80%
General Rate Revenue Increase Requested, Decrease						$ 6,000,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform						4,800,000
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform						$ 1,200,000
Percentage of Requested Allowed Rate of Return on Equity				9.77%
Equity to Total Capitalization Ratio Basis for Return on Equity				52.50%
Revenue Collected Under Interim Rates Subject to Refund																	3,400,000
Excess Revenue Collected for Income Taxes																	800,000
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2018 General Rate Case [Member]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 3,300,000
Increase in Annual Non-fuel Rates Requested, Step One, Percentage					10.10%
Increase in Annual Non-fuel Rates Requested, Step Two, Percentage					1.70%
Contract with Customer, Liability, Revenue Recognized																	1,000,000
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member]
Public Utilities General Rate Revenue Increase Approved														$ 643,000
Percentage of Increase in Base Rate Revenue Approved														2.32%
Public Utilities Allowed Rate of Return on Rate Base Subsequent to Approval of Increase in Base Rate														8.50%
Otter Tail Power Company [Member] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member]
Current Project Cost																	$ 106,000,000
Expanded Capacity of Projects																	345
Extended Distance of Transmission Line																	163
Percentage of Assets of Project																	100.00%
Otter Tail Power Company [Member] | Astoria Station Project [Member]
Expanded Capacity of Projects (MW)																	245
Current Project Capitalized Cost																	$ 7,700,000
Otter Tail Power Company [Member] | Merricourt Project [Member] | EDF [Member]
Expanded Capacity of Projects (MW)								150
Asset Purchase Agreement, Purchase Price								$ 34,700,000
Turnkey Engineering, Procurement and Construction Services Agreement, Costs								$ 200,500,000
Current Project Cost																	$ 5,300,000

Note 3 - Rate and Regulatory _4

Note 3 - Rate and Regulatory Matters - Summary of Status of Updates for Previous Two Years for Various Rate Riders (Details) - Otter Tail Power Company [Member] $ in Thousands		3 Months Ended
		Mar. 31, 2019USD ($)kWhBoe	Mar. 31, 2018USD ($)
Annual Revenue		$ 8,145	$ 10,116
Annual Revenue		8,145	10,116
MONTANA | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	[1]	2,152	2,516
Annual Revenue	[1]	$ 2,152	2,516
MONTANA | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member]
R - Request Date		Apr. 1, 2019
Effective Date Requested or Approved		Oct. 1, 2019
Annual Revenue		$ 11,926
Rate rider rate (Kilowatt-Hour) | kWh		0.0071
Annual Revenue		$ 11,926
MONTANA | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved		Nov. 1, 2018
Annual Revenue		$ 10,283
Rate rider rate (Kilowatt-Hour) | kWh		0.006
A - Approval Date		Oct. 4, 2018
Annual Revenue		$ 10,283
MONTANA | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved		Oct. 1, 2017
Annual Revenue		$ 9,868
Rate rider rate (Kilowatt-Hour) | kWh		0.00536
A - Approval Date		Sep. 15, 2017
Annual Revenue		$ 9,868
MONTANA | Transmission Cost Recovery Rider [Member]
Annual Revenue		641	(29)
Annual Revenue		$ 641	(29)
MONTANA | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member]
R - Request Date		Nov. 30, 2018
Effective Date Requested or Approved		Jun. 1, 2019
Annual Revenue		$ 6,475
Rate		Various
Annual Revenue		$ 6,475
MONTANA | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario B [Member]
Annual Revenue		$ 2,708
Rate		Various
Annual Revenue		$ 2,708
MONTANA | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Nov. 1, 2017
Annual Revenue		$ (3,311)
A - Approval Date		Oct. 30, 2017
Rate		Various
Annual Revenue		$ (3,311)
MONTANA | Environmental Cost Recovery Rider [Member]
Annual Revenue		(1)	(31)
Annual Revenue		$ (1)	(31)
MONTANA | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Nov. 1, 2017
Annual Revenue		$ (1,943)
A - Approval Date		Oct. 30, 2017
Rate of base		(0.935%)
Annual Revenue		$ (1,943)
MONTANA | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Dec. 1, 2018
Annual Revenue
A - Approval Date		Nov. 29, 2018
Rate of base		0.00%
Annual Revenue
MONTANA | Renewable Resource Adjustment [Member]
Annual Revenue		1,316	525
Annual Revenue		$ 1,316	525
MONTANA | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Nov. 1, 2017
Annual Revenue		$ 1,279
Rate rider rate (Kilowatt-Hour) | kWh		0.00049
A - Approval Date		Oct. 30, 2017
Annual Revenue		$ 1,279
MONTANA | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Nov. 1, 2018
Annual Revenue		$ 5,886
Rate rider rate (Kilowatt-Hour) | Boe		0.00244
A - Approval Date		Aug. 29, 2018
Annual Revenue		$ 5,886
NORTH DAKOTA | Transmission Cost Recovery Rider [Member]
Annual Revenue		1,772	2,062
Annual Revenue		$ 1,772	2,062
NORTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved		Mar. 1, 2018
Annual Revenue		$ 7,469
A - Approval Date		Feb. 27, 2018
Rate		Various
Annual Revenue		$ 7,469
NORTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member]
Effective Date Requested or Approved		Feb. 1, 2019
Annual Revenue		$ 4,801
A - Approval Date		Dec. 6, 2018
Rate		Various
Annual Revenue		$ 4,801
NORTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved		Jan. 1, 2018
Annual Revenue		$ 7,959
A - Approval Date		Nov. 29, 2017
Rate		Various
Annual Revenue		$ 7,959
NORTH DAKOTA | Environmental Cost Recovery Rider [Member]
Annual Revenue		575	1,821
Annual Revenue		$ 575	1,821
NORTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Jan. 1, 2018
Annual Revenue		$ 8,537
A - Approval Date		Dec. 20, 2017
Rate of base		6.629%
Annual Revenue		$ 8,537
NORTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved		Feb. 1, 2019
Annual Revenue		$ (378)
A - Approval Date		Dec. 19, 2018
Rate of base		(0.31%)
Annual Revenue		$ (378)
NORTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved		Mar. 1, 2018
Annual Revenue		$ 7,718
A - Approval Date		Feb. 27, 2018
Rate of base		5.593%
Annual Revenue		$ 7,718
NORTH DAKOTA | Renewable Resource Adjustment [Member]
Annual Revenue		729	1,967
Annual Revenue		$ 729	1,967
NORTH DAKOTA | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved		Jan. 1, 2018
Annual Revenue		$ 9,989
A - Approval Date		Dec. 20, 2017
Rate of base		7.756%
Annual Revenue		$ 9,989
NORTH DAKOTA | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved		Jun. 1, 2019
Annual Revenue		$ (235)
A - Approval Date		May 1, 2019
Rate of base		(0.224%)
Annual Revenue		$ (235)
NORTH DAKOTA | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved		Mar. 1, 2018
Annual Revenue		$ 9,650
A - Approval Date		Feb. 27, 2018
Rate of base		7.493%
Annual Revenue		$ 9,650
NORTH DAKOTA | Generation Cost Recovery [Member]
Annual Revenue		248
Annual Revenue		$ 248
NORTH DAKOTA | Generation Cost Recovery [Member] | The 2019 Initial Request [Member]
R - Request Date		Mar. 1, 2019
Effective Date Requested or Approved		Jul. 1, 2019
Annual Revenue		$ 2,720
Rate of base		2.547%
Annual Revenue		$ 2,720
SOUTH DAKOTA | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue		244	229
Annual Revenue		244	229
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member]
Annual Revenue		473	536
Annual Revenue		$ 473	536
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member]
Effective Date Requested or Approved		Mar. 1, 2019
Annual Revenue		$ 1,638
A - Approval Date		Feb. 20, 2019
Rate		Various
Annual Revenue		$ 1,638
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved		Mar. 1, 2018
Annual Revenue		$ 1,779
A - Approval Date		Feb. 28, 2018
Rate		Various
Annual Revenue		$ 1,779
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved		Oct. 18, 2018
Annual Revenue		$ 1,171
A - Approval Date		Oct. 18, 2018
Rate		Various
Annual Revenue		$ 1,171
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved		Mar. 1, 2017
Annual Revenue		$ 2,053
A - Approval Date		Feb. 17, 2017
Rate		Various
Annual Revenue		$ 2,053
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member]
Annual Revenue		(4)	520
Annual Revenue		$ (4)	$ 520
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved		Nov. 1, 2017
Annual Revenue		$ 2,082
Rate rider rate (Kilowatt-Hour) | Boe		0.00483
A - Approval Date		Oct. 13, 2017
Annual Revenue		$ 2,082
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
Effective Date Requested or Approved		Oct. 18, 2018
Annual Revenue		$ (189)
Rate rider rate (Kilowatt-Hour) | kWh		(0.00075)
A - Approval Date		Oct. 18, 2018
Annual Revenue		$ (189)
[1]	Includes MNCIP costs recovered in base rates.

Note 3 - Rate and Regulatory _5

Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Revenues recorded under rate riders		$ 8,145	$ 10,116
MONTANA | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	[1]	2,152	2,516
MONTANA | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		1,316	525
MONTANA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		641	(29)
MONTANA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		(1)	(31)
NORTH DAKOTA | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		729	1,967
NORTH DAKOTA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,772	2,062
NORTH DAKOTA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		575	1,821
NORTH DAKOTA | Generation Cost Recovery [Member]
Revenues recorded under rate riders		248
SOUTH DAKOTA | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders		244	229
SOUTH DAKOTA | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		473	536
SOUTH DAKOTA | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		$ (4)	$ 520
[1]	Includes MNCIP costs recovered in base rates.

Note 4 - Regulatory Assets an_3

Note 4 - Regulatory Assets and Liabilities (Details Textual)	3 Months Ended
	Mar. 31, 2019
Regulatory Noncurrent Asset, Remaining Recovery Period	13 years 180 days

Note 4 - Regulatory Assets an_4

Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
		Mar. 31, 2019	Dec. 31, 2018
Regulatory Assets - Current		$ 15,193	$ 17,225
Regulatory Assets - Long -Term		133,427	135,257
Regulatory Assets - Total		$ 148,620	$ 152,482
Regulatory Assets - Remaining Recovery/Refund Period (Month)
Regulatory Liabilities - Current		$ 7,787	$ 738
Regulatory Liabilities - Long -Term		225,496	226,469
Regulatory Liabilities, Total		$ 233,283	$ 227,207
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)
Net Regulatory Asset Position - Current		$ 7,406	$ 16,487
Net Regulatory Asset Position - Long-Term		(92,069)	(91,212)
Net Regulatory Asset/(Liability) Position		(84,663)	(74,725)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		141,452	142,779
Regulatory Liabilities, Total		$ 141,452	$ 142,779
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		83,555	83,229
Regulatory Liabilities, Total		$ 83,555	$ 83,229
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 901	$ 177
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 901	$ 177
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 272	$ 60
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 272	$ 60
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues - Minnesota [Member]
Regulatory Liabilities - Current		$ 5,149
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 5,149
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		225	166
Regulatory Liabilities, Total		$ 225	$ 166
Regulatory Liabilities - Remaining Recovery/Refund Period		see below	see below
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		187	187
Regulatory Liabilities, Total		$ 187	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 270 days	2 years
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 669
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 669
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 151	$ 168
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 151	$ 168
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues – North Dakota [Member]
Regulatory Liabilities - Current		$ 537
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 537
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 103	$ 207
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total		$ 103	$ 207
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current			$ 121
Regulatory Liabilities - Long -Term
Regulatory Liabilities, Total			$ 121
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year
Other [Member]
Regulatory Liabilities - Current		$ 5	$ 5
Regulatory Liabilities - Long -Term		77	108
Regulatory Liabilities, Total		$ 82	$ 113
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		14 years 270 days	15 years
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 6,355	$ 6,346
Regulatory Assets - Long -Term	[1]	116,835	118,433
Regulatory Assets - Total	[1]	$ 123,190	$ 124,779
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	7,302	7,169
Regulatory Assets - Total	[1]	$ 7,302	$ 7,169
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 3,007	$ 5,995
Regulatory Assets - Long -Term	[2]	3,979	3,285
Regulatory Assets - Total	[2]	$ 6,986	$ 9,280
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year 180 days	1 year 270 days
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 1,432	$ 1,661
Regulatory Assets - Long -Term	[1]	557	743
Regulatory Assets - Total	[1]	$ 1,989	$ 2,404
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year 270 days	2 years
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 1,958	$ 444
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 1,958	$ 444
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Deferred Income Taxes [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	1,557	2,423
Regulatory Assets - Total	[1]	$ 1,557	$ 2,423
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 689	$ 681
Regulatory Assets - Long -Term	[1]	770	947
Regulatory Assets - Total	[1]	$ 1,459	$ 1,628
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 30 days	2 years 120 days
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	1,143	986
Regulatory Assets - Total	[1]	$ 1,143	$ 986
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 203	$ 207
Regulatory Assets - Long -Term	[1]	701	753
Regulatory Assets - Total	[1]	$ 904	$ 960
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	13 years 180 days	13 years 270 days
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 416	$ 455
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 416	$ 455
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 117	$ 100
Regulatory Assets - Long -Term	[1]	292	342
Regulatory Assets - Total	[1]	$ 409	$ 442
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	3 years 180 days	4 years 150 days
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]	$ 180	$ 240
Regulatory Assets - Long -Term	[1]	130
Regulatory Assets - Total	[1]	$ 310	$ 240
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 270 days	1 year
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 267	$ 178
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 267	$ 178
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
North Dakota Generation Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 248
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 248
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year
Minnesota SPP Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	117	176
Regulatory Assets - Total	[1]	$ 117	$ 176
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Recoverable Fuel and Purchased Power Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 197
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 197
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]	$ 52	$ 328
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 52	$ 328
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	120 days	120 days
Minnesota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 38	$ 121
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 38	$ 121
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 34	$ 452
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 34	$ 452
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year	1 year
Deferred Lease Expenses [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	44
Regulatory Assets - Total	[1]	$ 44
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	4 years
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 17
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 17
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year
[1]	Costs subject to recovery without a rate of return.
[2]	Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Note 5 - Common Shares and Ea_3

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

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
	Mar. 31, 2019	Mar. 31, 2018
Weighted Average Common Shares Outstanding – Basic (in shares)	39,657,321	39,550,874
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares)	158,159	223,162
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	63,398	59,130
Nonvested Restricted Shares (in shares)	21,922	27,643
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,365	2,873
Total Dilutive Shares (in shares)	245,844	312,808
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,903,165	39,863,682

Note 6 - Share-based Payments_2

Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions	Feb. 05, 2018	Mar. 31, 2019
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total		$ 6.2
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition		2 years 73 days
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	55,600
Period Specified for Average Adjusted Return	3 years
Number of Trading Days	20 days
Number of Shares Authorized for Actual Payment	83,400
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member]
Percentage of Target Amount as Actual Payment	0.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member]
Percentage of Target Amount as Actual Payment	150.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,800

Note 6 - Share-based Payments -

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

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)	Feb. 13, 2019
The 2014 Stock Incentive Plan [Member]
Shares/units granted, vesting percentage	25.00%

Note 6 - Share-based Payments_4

Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Stock compensation expense	$ 1,796	$ 1,146
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	1,113	651
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	427	249
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense		16
Restricted Stock [Member] | Director [Member]
Stock compensation expense	165	166
Restricted Stock [Member] | Non-executive Employees [Member]
Stock compensation expense	$ 91	$ 64

Note 7 - Retained Earnings an_2

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

Note 8 - Leases (Details Textua

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

Note 8 - Leases - Lease Assets

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

Note 8 - Leases - Lease Obligat

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

Note 8 - Leases - Operating Lea

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

Note 8 - Leases - Allocation of

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

Note 9 - Commitments and Cont_2

Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1.6
Otter Tail Power Company [Member] | Construction Programs [Member]
Long-term Purchase Commitment, Amount	$ 70.5	$ 64.5
Contract Expiration Year	2021
Otter Tail Power Company [Member] | Capacity and Energy Requirements [Member]
Contract Expiration Year	2042
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2040
Otter Tail Power Company [Member] | Coal Purchase Commitments 3 [Member]
Contract Expiration Year	2020
Otter Tail Power Company [Member] | OTP Land Easements [Member]
Long-term Purchase Commitment, Amount	$ 10.8
Contract Expiration Year	2034
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount	$ 4.7	$ 5

Note 10 - Short-term and Long_3

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

Note 10 - Short-term and Long_4

Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Short-Term Debt	$ 43,601	$ 18,599
Long-Term Debt	592,480	592,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	174	172
Unamortized Long-Term Debt Issuance Costs	2,284	2,349
Total Long-Term Debt net of Unamortized Debt Issuance Costs	590,022	590,002
Total Short-Term and Long-Term Debt (with current maturities)	633,797	608,773
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000	100,000
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	480	523
Otter Tail Power Company [Member]
Short-Term Debt	15,859	9,384
Long-Term Debt	512,000	512,000
Less: Current Maturities net of Unamortized Debt Issuance Costs
Unamortized Long-Term Debt Issuance Costs	1,890	1,942
Total Long-Term Debt net of Unamortized Debt Issuance Costs	510,110	510,058
Total Short-Term and Long-Term Debt (with current maturities)	525,969	519,442
Otter Tail Power Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000	100,000
Otter Tail Power Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt
Parent Company [Member]
Short-Term Debt	27,742	9,215
Long-Term Debt	80,480	80,523
Less: Current Maturities net of Unamortized Debt Issuance Costs	174	172
Unamortized Long-Term Debt Issuance Costs	394	407
Total Long-Term Debt net of Unamortized Debt Issuance Costs	79,912	79,944
Total Short-Term and Long-Term Debt (with current maturities)	107,828	89,331
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Parent Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 480	$ 523

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) (Parentheticals)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt, Interest Rate	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt, Interest Rate	4.07%	4.07%
Long-Term Debt, Due Date	Feb. 7, 2048	Feb. 7, 2048
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]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

Note 11 - Pension Plan and Ot_3

Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual) $ in Millions	1 Months Ended
	Jan. 31, 2019USD ($)
Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 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
		Mar. 31, 2019	Mar. 31, 2018
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,373	$ 1,615
Interest Cost on Projected Benefit Obligation		3,603	3,363
Expected Return on Assets		(5,325)	(5,300)
From Regulatory Asset		1	4
From Other Comprehensive Income	[1]	2
From Regulatory Asset		1,163	1,784
From Other Comprehensive Income	[1]	27	44
Net Periodic Pension Cost	[2]	844	1,510
From Other Comprehensive Income	[1]	27	44
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		390	328
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		950	1,247
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		33	40
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		(150)	(21)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		(379)	(84)
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		105	100
Interest Cost on Projected Benefit Obligation		434	399
From Regulatory Asset		1	4
From Other Comprehensive Income	[3]	4	10
From Regulatory Asset		31	67
From Other Comprehensive Income	[3]	87	165
Net Periodic Pension Cost	[4]	662	745
From Other Comprehensive Income	[3]	87	165
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		26	25
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		79	75
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		557	645
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		321	382
Interest Cost on Projected Benefit Obligation		770	645
From Regulatory Asset		393	412
From Other Comprehensive Income	[1]	10	10
Net Periodic Pension Cost	[5]	1,494	1,449
From Other Comprehensive Income	[1]	10	10
Effect of Medicare Part D Subsidy		(45)	(37)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		91	78
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		223	294
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		7	10
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		333	217
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		$ 840	$ 850
[1]	Corporate cost included in nonservice cost components of postretirement benefits.
[2]	Allocation of Costs: Service costs included in OTP capital expenditures $ 390 $ 328 Service costs included in electric operation and maintenance expenses 950 1,247 Service costs included in other nonelectric expenses 33 40 Nonservice costs capitalized as regulatory assets (150 ) (21 ) Nonservice costs included in nonservice cost components of postretirement benefits (379 ) (84 )
[3]	Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits.
[4]	Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 25 Service costs included in other nonelectric expenses 79 75 Nonservice costs included in nonservice cost components of postretirement benefits 557 645
[5]	Allocation of Costs: Service costs included in OTP capital expenditures $ 91 $ 78 Service costs included in electric operation and maintenance expenses 223 294 Service costs included in other nonelectric expenses 7 10 Nonservice costs capitalized as regulatory assets 333 217 Nonservice costs included in nonservice cost components of postretirement benefits 840 850

Note 12 - Fair Value of Finan_3

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

Note 12 - Fair Value of Finan_4

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

Note 14 - Income Tax Expense _3

Note 14 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Period for Unrecognized Tax Benefits Not Expected Change	1 year
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ 0

Note 14 - Income Tax Expense _4

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

Note 14 - Income Tax Expense _5

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

Note 14 - Income Tax Expense _6

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