Otter Tail (OTTR) 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document Information [Line Items]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	1,466,593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding (in shares)		39,664,883
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Amendment Flag	false

Consolidated Balance Sheets (Cu

Consolidated Balance Sheets (Current Period Not Audited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 1,036	$ 16,216
Accounts Receivable:
Trade—Net	91,780	68,466
Other	10,224	7,761
Inventories	90,435	88,034
Unbilled Receivables	18,278	22,427
Income Taxes Receivable		1,181
Regulatory Assets	17,914	22,551
Other	9,574	12,491
Total Current Assets	239,241	239,127
Investments	8,649	8,629
Other Assets	36,519	36,006
Goodwill	37,572	37,572
Other Intangibles—Net	13,075	13,765
Regulatory Assets	123,631	129,576
Plant
Electric Plant in Service	1,993,738	1,981,018
Nonelectric Operations	223,323	216,937
Construction Work in Progress	168,372	141,067
Total Gross Plant	2,385,433	2,339,022
Less Accumulated Depreciation and Amortization	832,873	799,419
Net Plant	1,552,560	1,539,603
Total Assets	2,011,247	2,004,278
Current Liabilities
Short-Term Debt	20,977	112,371
Current Maturities of Long-Term Debt	167	186
Accounts Payable	95,082	84,185
Accrued Salaries and Wages	18,460	21,534
Accrued Federal and State Income Taxes	673
Other Accrued Taxes	10,963	16,808
Regulatory Liabilities	7,248	9,688
Other Accrued Liabilities	12,665	11,389
Liabilities of Discontinued Operations		492
Total Current Liabilities	166,235	256,653
Pensions Benefit Liability	89,424	109,708
Other Postretirement Benefits Liability	70,203	69,774
Other Noncurrent Liabilities	25,060	22,769
Commitments and Contingencies (note 8)
Deferred Credits
Deferred Income Taxes	104,382	100,501
Deferred Tax Credits	20,676	21,379
Regulatory Liabilities - Long -Term	228,163	232,893
Other	2,563	3,329
Total Deferred Credits	355,784	358,102
Capitalization
Long-Term Debt—Net	589,960	490,380
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2018—39,651,436 Shares; 2017—39,557,491 Shares	198,257	197,787
Premium on Common Shares	342,690	343,450
Retained Earnings	179,605	161,286
Accumulated Other Comprehensive Loss	(5,971)	(5,631)
Total Common Equity	714,581	696,892
Total Capitalization	1,304,541	1,187,272
Total Liabilities and Equity	2,011,247	2,004,278
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares

Consolidated Balance Sheets (C3

Consolidated Balance Sheets (Current Period Not Audited) (Parentheticals) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized (in shares)	50,000,000	50,000,000
Common shares, outstanding (in shares)	39,651,436	39,557,491
Cumulative Preferred Shares [Member]
Cumulative shares, authorized (in shares)	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0
Cumulative Preference Shares [Member]
Cumulative shares, authorized (in shares)	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding (in shares)	0	0

Consolidated Statements of Inco

Consolidated Statements of Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues:
Operating Revenues	$ 226,348	$ 212,086	$ 467,614	$ 426,203
Operating Expenses
Production Fuel – Electric	15,888	12,477	34,594	28,859
Cost of Products Sold (depreciation included below)	93,545	84,013	182,330	159,290
Electric Operation and Maintenance Expenses	37,741	36,748	77,216	74,025
Other Nonelectric Expenses	12,649	9,859	25,143	19,994
Depreciation and Amortization	18,745	17,908	37,508	35,762
Property Taxes – Electric	3,273	3,709	7,108	7,507
Total Operating Expenses	196,243	181,090	399,894	361,001
Operating Income	30,105	30,996	67,720	65,202
Interest Charges	7,676	7,527	15,048	14,989
Nonservice Cost Components of Postretirement Benefits	1,386	1,407	2,803	2,812
Other Income	707	552	1,890	1,105
Income Before Income Taxes – Continuing Operations	21,750	22,614	51,759	48,506
Income Tax Expense – Continuing Operations	3,054	5,897	6,848	12,260
Net Income from Continuing Operations	18,696	16,717	44,911	36,246
Discontinued Operations
Income – net of Income Tax Expense of $0, $40, $0 and $78 for the respective periods		61		117
Net Income	$ 18,696	$ 16,778	$ 44,911	$ 36,363
Average Number of Common Shares Outstanding – Basic (in shares)	39,605,717	39,462,865	39,578,296	39,406,834
Average Number of Common Shares Outstanding – Diluted (in shares)	39,879,069	39,702,499	39,871,376	39,671,612
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 0.47	$ 0.43	$ 1.13	$ 0.92
Discontinued Operations (in dollars per share)
(in dollars per share)	0.47	0.43	1.13	0.92
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	0.47	0.42	1.13	0.92
Discontinued Operations (in dollars per share)
(in dollars per share)	0.47	0.42	1.13	0.92
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32	$ 0.67	$ 0.64
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 105,284	$ 102,655	$ 229,109	$ 222,437
Changes in Accrued Revenues under Alternative Revenue Programs	(1,565)	(424)	(2,440)	(1,663)
Operating Revenues	103,719	102,231	226,669	220,774
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	122,629	109,855	240,945	205,429
Electricity, Purchased [Member]
Operating Expenses
Cost of Products Sold (depreciation included below)	$ 14,402	$ 16,376	$ 35,995	$ 35,564

Consolidated Statements of Inc5

Consolidated Statements of Income (Not Audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Expense - Discontinued Operations	$ 0	$ 40	$ 0	$ 78

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net Income	$ 18,696	$ 16,778	$ 44,911	$ 36,363
Unrealized (Loss) Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period		(1)	(110)	(1)
Unrealized (Losses) Gains Arising During Period	(13)	21	(79)	38
Income Tax Benefit (Expense)	3	(7)	40	(13)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax	(10)	13	(149)	24
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10)	233	159	460	316
Income Tax Expense	(61)	(63)	(120)	(126)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act			(531)
Pension and Postretirement Benefit Plans – net-of-tax	172	96	(191)	190
Total Other Comprehensive Income (Loss)	162	109	(340)	214
Total Comprehensive Income	$ 18,858	$ 16,887	$ 44,571	$ 36,577

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash Flows from Operating Activities
Net Income	$ 44,911	$ 36,363
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		(117)
Depreciation and Amortization	37,508	35,762
Deferred Tax Credits	(703)	(734)
Deferred Income Taxes	2,076	8,666
Change in Deferred Debits and Other Assets	10,309	8,075
Discretionary Contribution to Pension Plan	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	(759)	(695)
Allowance for Equity/Other Funds Used During Construction	(1,060)	(401)
Stock Compensation Expense—Equity Awards	2,253	1,920
Other—Net	(193)	39
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(25,677)	(12,832)
Change in Inventories	(2,401)	(3,527)
Change in Other Current Assets	2,428	2,095
Change in Payables and Other Current Liabilities	1,433	(5,878)
Change in Interest and Income Taxes Receivable/Payable	3,470	590
Net Cash Provided by Continuing Operations	53,595	69,326
Net Cash Used in Discontinued Operations	(200)	(54)
Net Cash Provided by Operating Activities	53,395	69,272
Cash Flows from Investing Activities
Capital Expenditures	(49,094)	(56,354)
Net Proceeds from Disposal of Noncurrent Assets	1,477	2,167
Cash Used for Investments and Other Assets	(2,102)	(2,431)
Net Cash Used in Investing Activities	(49,719)	(56,618)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	2,236	1,043
Net Short-Term (Repayments) Borrowings	(91,394)	15,234
Proceeds from Issuance of Common Stock		4,266
Common Stock Issuance Expenses	(108)
Payments for Retirement of Capital Stock	(2,450)	(1,799)
Proceeds from Issuance of Long-Term Debt	100,000
Short-Term and Long-Term Debt Issuance Expenses	(441)
Payments for Retirement of Long-Term Debt	(107)	(6,114)
Dividends Paid	(26,592)	(25,284)
Net Cash Used in Financing Activities	(18,856)	(12,654)
Net Change in Cash and Cash Equivalents	(15,180)
Cash and Cash Equivalents at Beginning of Period	16,216
Cash and Cash Equivalents at End of Period	$ 1,036

Note 1 - Summary of Significant

Note 1 - Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Significant Accounting Policies and New Accounting Pronouncements [Text Block]	1. Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 six June 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three six June 30, 2018 2017. 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 June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company 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 June 30, 2018 $55.7 35% Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: June 30, December 31, (in thousands) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first six 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312 New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01 December 15, 2017, 2016 01 first 2018, ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three six June 30, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. 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. ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $0.8

Note 2 - Segment Information

Note 2 - Segment Information	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Segment Reporting Disclosure [Text Block]	2. Segment Information Segment Information The accounting policies of the segments are described under note 1 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, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not No 10% 2017. one 11.7% 2017 one 24.3% 2017 one 12.0% 2017 two 20.6% 17.8% 2017 one All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.2% 98.3% three June 30, 2018 2017, 98.3% 98.3% six June 30, 2018 2017. 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 six June 30, 2018 2017 June 30, 2018 December 31, 2017 Operating Revenue Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 89,400 $ 86,679 $ 198,580 $ 193,133 Changes in Accrued ARP Revenues (1,565 ) (424 ) (2,440 ) (1,663 ) Total Retail Sales Revenue 87,835 86,255 196,140 191,470 Wholesale Revenues – Company Generation 2,539 1,184 3,554 2,051 Other Revenues 13,351 14,797 26,996 27,266 Total Electric Segment Revenues $ 103,725 $ 102,236 $ 226,690 $ 220,787 Manufacturing Segment: Metal Parts and Tooling $ 57,388 $ 49,450 $ 114,315 $ 97,528 Plastic Products and Tooling 7,961 7,376 18,196 16,928 Other 2,805 2,478 4,305 3,265 Total Manufacturing Segment Revenues $ 68,154 $ 59,304 $ 136,816 $ 117,721 Plastics Segment – Sale of PVC Pipe Products $ 54,476 $ 50,551 $ 104,129 $ 87,708 Intersegment Eliminations $ (7 ) $ (5 ) $ (21 ) $ (13 ) Total $ 226,348 $ 212,086 $ 467,614 $ 426,203 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,687 $ 6,439 $ 13,077 $ 12,825 Manufacturing 555 553 1,109 1,107 Plastics 160 173 310 326 Corporate and Intersegment Eliminations 274 362 552 731 Total $ 7,676 $ 7,527 $ 15,048 $ 14,989 Income Taxes Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 611 $ 2,442 $ 2,709 $ 8,504 Manufacturing 1,018 1,573 2,241 2,628 Plastics 2,207 2,858 4,621 4,248 Corporate (782 ) (976 ) (2,723 ) (3,120 ) Total $ 3,054 $ 5,897 $ 6,848 $ 12,260 Net Income (Loss) Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 10,600 $ 10,134 $ 27,268 $ 25,694 Manufacturing 3,583 2,955 7,747 5,127 Plastics 6,229 4,637 13,073 7,074 Corporate (1,716 ) (1,009 ) (3,177 ) (1,649 ) Discontinued Operations -- 61 -- 117 Total $ 18,696 $ 16,778 $ 44,911 $ 36,363 Identifiable Assets June 30, December 31, (in thousands) 2018 2017 Electric $ 1,687,799 $ 1,690,224 Manufacturing 181,094 167,023 Plastics 99,205 87,230 Corporate 43,149 59,801 Total $ 2,011,247 $ 2,004,278

Note 3 - Rate and Regulatory Ma

Note 3 - Rate and Regulatory Matters	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Public Utilities Disclosure [Text Block]	3. Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2018 2017. Major Capital Expenditure Projects Big Stone South–Ellendale Multi-Value Transmission Project (MVP) 345 163 December 2011. second 2016 2019. June 30, 2018 $99.4 100% Big Stone South–Brookings MVP 345 70 December 2011. third 2015 September 8, 2017. June 30, 2018 $72.5 100% Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota General Rate s 2016 March 2017 May 1, 2017. 8.61% 7.5056% 10.74% 9.41%. The MPUC’s order also included: ( 1 2 OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 November 17, 2017. 1 2 9.41% 2016 April 16, 2016, October 31, 2017, $0.9 $1.4 12 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 Based on results from the 2017 $2.6 2017. 2017 10% 2016 2017 not $2.6 March 30, 2018. June 13, 2018, May 30, 2018, $2.9 July 3, 2018 $2.6 July 13, 2018 $2.9 Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 June 30, 2018, $2.0 Environmental Cost Recovery Rider 2010 2016 November 2017. Renewable Resource Adjustment November 1, 2017, one 2017 2018. $1.3 $5.8 2018 November 1, 2018. North Dakota General Rates November 2, 2017 $13.1 8.72%. $13.1 7.97% 10.30%. December 20, 2017 $12.8 January 1, 2018. February 27, 2018 $4.5 $8.3 March 1, 2018. 2018 On March 23, 2018 $13.1 $7.1 4.8% $6.0 $4.8 $1.2 July 6, 2018. 9.77% 52.5% $5.4 March 2018 $7.1 4.8% 10.3%. no 2017 $1.8 June 30, 2018 third OTP’s previously approved general rate increase in North Dakota of $3.6 3.0%, November 25, 2009 December 2009. 8.62%, 10.75%. Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider South Dakota General Rate s April 20, 2018 $3.3 10.1%, first two October 18, 2018. second 1.7% OTP’s previously approved general rate increase in South Dakota of approximately $643,000 2.32% April 21, 2011 June 1, 2011. 8.50%. Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2016 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2017 Incentive and Cost Recovery R – March 30, 2018 October 1, 2018 $ 10,300 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2018 Annual Update R – July 3, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2018 Annual Update R – June 14, 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 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 1 Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket. 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: Revenues R ecorded under R ider R ates Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,368 $ 2,102 $ 4,884 $ 4,068 Transmission Cost Recovery (458 ) 1,273 (487 ) 3,443 Environmental Cost Recovery (18 ) 2,812 (49 ) 5,636 Renewable Resource Recovery 659 -- 1,184 -- North Dakota Renewable Resource Adjustment 2,079 1,839 4,046 3,609 Transmission Cost Recovery 1,165 1,384 3,227 3,895 Environmental Cost Recovery 1,830 2,388 3,651 4,876 South Dakota Transmission Cost Recovery 250 287 786 728 Environmental Cost Recovery 515 545 1,035 1,142 Conservation Improvement Program Costs and Incentives 122 176 351 416 Total $ 8,512 $ 12,806 $ 18,628 $ 27,813 1 Includes MNCIP costs recovered in base rates. TCJA The TCJA reduced the federal corporate income tax rate from 35% 21%. 35% February 15, 2018 not February 1, 2018 December 31, 2017 June 30, 2018, $4.1 $0.8 January February 2018, $0.7 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 one MVPs—On December 16, 2010 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 June 30, 2018. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second second first

Note 4 - Regulatory Assets and

Note 4 - Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 2018
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 Topic 980, Regulated Operations 980 980 605 25 June 30, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 107,946 $ 117,036 see below Conservation Improvement Program Costs and Incentives 2 3,927 4,163 8,090 27 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,907 6,907 asset lives Deferred Marked-to-Market Losses 1 2,862 1,574 4,436 30 Big Stone II Unrecovered Project Costs – Minnesota 1 665 1,296 1,961 34 Debt Reacquisition Premiums 1 231 856 1,087 171 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 513 -- 513 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 392 492 59 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 422 422 asset lives North Dakota Deferred Rate Case Expenses Subject to Recovery 1 303 -- 303 12 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 223 -- 223 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 75 75 18 Total Regulatory Assets $ 17,914 $ 123,631 $ 141,545 Regulatory Liabilities: Deferred Income Taxes $ -- $ 147,858 $ 147,858 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 79,835 79,835 asset lives Refundable Fuel Clause Adjustment Revenues 4,972 -- 4,972 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 716 -- 716 4 North Dakota Renewable Resource Recovery Rider Accrued Refund 394 -- 394 9 North Dakota Transmission Cost Recovery Rider Accrued Refund 319 -- 319 12 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker -- 316 316 see below South Dakota Environmental Cost Recovery Rider Accrued Refund 308 -- 308 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 240 -- 240 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 231 -- 231 12 Other 6 81 87 186 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 61 24 85 18 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 49 49 see below Minnesota Renewable Resource Recovery Rider Accrued Refund 1 -- 1 4 Total Regulatory Liabilities $ 7,248 $ 228,163 $ 235,411 Net Regulatory Asset/(Liability) Position $ 10,666 $ (104,532 ) $ (93,866 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. All Deferred Marked-to-Market Losses recorded as of June 30, 2018 December 2020. Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 171 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. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The 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. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota and are currently being recovered beginning with the establishment of interim rates in January 2018. Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that have not June 30, 2018. MISO Schedule 26/26A 26/26A North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had not December 31, 2017. Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 24 April 2016. North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that had not December 31, 2017. The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of June 30, 2018. The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of June 30, 2018. 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 June 30, 2018. The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund. 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 June 30, 2018. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that are recoverable from North Dakota customers as of June 30, 2018. The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of June 30, 2018. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which were subject to refund over a 24 April 2016. The Minnesota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of June 30, 2018. The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were refundable to Minnesota customers as of December 31, 2017. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980

Note 5 - Reconciliation of Comm

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Stockholders Equity and Earnings per Share [Text Block]	5 . Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share Reconciliation of Common Shareholders’ Equity (in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 767 (860 ) (93 ) Common Stock Retirements (297 ) (2,153 ) (2,450 ) Net Income 44,911 44,911 Other Comprehensive Loss (340 ) (340 ) Employee Stock Incentive Plans Expense 2,253 2,253 Common Dividends ($0.67 per share) (26,592 ) (26,592 ) Balance, June 30, 2018 $ 198,257 $ 342,690 $ 179,605 $ (5,971 ) $ 714,581 Shelf Registration s and Common Share Distribution Agreement On May 3, 2018 may May 3, 2021. May 3, 2018, 1,500,000 May 3, 2021. May 11, 2018. May 1, 2018 may Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 June 30, 2018: Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 19,950 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (59,431 ) Common Shares Outstanding, June 30, 2018 39,651,436 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three six June 30, 2018 2017. not Three Months ended June 30 Six Months ended June 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,605,717 39,462,865 39,578,296 39,406,834 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 202,643 173,974 212,902 187,806 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,616 50,087 58,373 53,980 Nonvested Restricted Shares 10,733 12,719 19,188 19,894 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,360 2,854 2,617 3,098 Total Dilutive Shares 273,352 239,634 293,080 264,778 Weighted Average Common Shares Outstanding – Diluted 39,879,069 39,702,499 39,871,376 39,671,612 The effect of dilutive shares on earnings per share for the three six June 30, 2018 2017, no $ 0.01

Note 6 - Share-based Payments

Note 6 - Share-based Payments	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	6 . Share-Based Payments Stock Incentive Awards The following stock incentive awards were granted under the 2014 six June 30, 2018: Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted to Executive Officers February 5, 2018 54,000 $ 35.73 December 31, 2020 Restricted Stock Units Granted to Executive Officers February 5, 2018 15,200 $ 41.325 25% per year through February 6, 2022 Restricted Stock Units Granted to Key Employees April 9, 2018 12,945 $ 38.45 100% on April 8, 2022 Restricted Stock Units Granted to Key Employee June 20, 2018 1,000 $ 42.46 100% on April 8, 2022 Restricted Stock Granted to Nonemployee Directors April 9, 2018 18,200 $ 43.40 33% per year through April 8, 2021 Under the performance share awards the aggregate award for performance at target is 54,000 27,000 3 27,000 January 1, 2018 December 31, 2020, 20 January 1, 2018 20 January 1, 2021. may zero 150% 81,000 no 718, The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price of one not one The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not one The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of June 30, 2018, $6.2 2.2 Amounts of compensation expense recognized under the Company’s five three six June 30, 2018 2017 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 668 $ 425 $ 1,319 $ 1,074 Restricted Stock Units Granted to Executive Officers 173 104 422 368 Restricted Stock Granted to Executive Officers -- 16 16 38 Restricted Stock Granted to Nonemployee Directors 165 144 331 272 Restricted Stock Units Granted to Key Employees 101 81 165 168 Totals $ 1,107 $ 770 $ 2,253 $ 1,920

Note 7 - Retained Earnings and

Note 7 - Retained Earnings and Dividend Restriction	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Retained Earnings Restrictions [Text Block]	7 . Retained Earnings 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 June 30, 2018, 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 47.4% 58.0% 2017 September 1, 2017. June 30, 2018, 52.5% $473,000,000. $1,178,024,000. On May 1, 2018 47.9% 58.5% 2018 not $1,204,416,000. June 15, 2018

Note 8 - Commitments and Contin

Note 8 - Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	8 . Commitments and Contingencies Construction and Other Purchase Commitments At June 30, 2018 2019 $45.3 December 31, 2017 2019 $41.0 June 30, 2018 December 31, 2021 $5.8 December 31, 2017 December 31, 2021 $6.7 Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2041. 2040. 2020. May 14, 2018 December 31, 2020. no 2018 2019 December 31, 2023. no Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. In the first 2018, May 2018 June 2021, $216,000 2018, $324,000 2019, $324,000 2020 $162,000 2021. June 2018 63 July 2018 September 2023, $79,000 2018, $322,000 2019, $332,000 2020, $342,000 2021, $352,000 2022 $271,000 2023. Contingencies OTP had a $1.6 June 30, 2018 Together with as many as 200 April 1, 2005 May 2, 2015. not June 28, 2018 not July 30, 2018. No Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as $1.0 In 2014 CO2 CO2 111 October 23, 2015. February 9, 2016 September 27, 2016 first 2017. 13783, CO2 October 16, 2017 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 June 30, 2018 not

Note 9 - Short-term and Long-te

Note 9 - Short-term and Long-term Borrowings	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Debt Disclosure [Text Block]	9 . Short-Term and Long-Term Borrowings The following table presents the status of the Company’s lines of credit as of June 30, 2018 December 31, 2017: (in thousands) Line Limit In Use on June 30, 2018 Restricted due to Outstanding Letters of Credit Available on June 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,102 $ -- $ 123,898 $ 130,000 OTP Credit Agreement 170,000 14,875 300 154,825 57,329 Total $ 300,000 $ 20,977 $ 300 $ 278,723 $ 187,329 Debt Issuances 2018 On November 14, 2017, 2018 $100 4.07% 2018A February 7, 2048 ( 2018 2018 February 7, 2018. 2018 OTP may not 10% 100% no August 7, 2047 2018 100% 2018 The 2018 2018 2018 not 2018 not 2018 2018 2018 2018 2018 2018 no The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 14,875 $ 6,102 $ 20,977 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, fully repaid April 1, 2018 -- -- PACE Note, 2.54%, due March 18, 2021 604 604 Total $ 512,000 $ 80,604 $ 592,604 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 167 167 Unamortized Long-Term Debt Issuance Costs 2,045 432 2,477 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,955 $ 80,005 $ 589,960 Total Short-Term and Long-Term Debt (with current maturities) $ 524,830 $ 86,274 $ 611,104 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937

Note 10 - Pension Plan and Othe

Note 10 - Pension Plan and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Pension and Other Postretirement Benefits Disclosure [Text Block]	1 0 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 3,230 $ 2,814 Interest Cost on Projected Benefit Obligation 3,363 3,536 6,726 7,070 Expected Return on Assets (5,299 ) (4,807 ) (10,599 ) (9,614 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 29 8 59 From Other Comprehensive Income 1 -- 1 -- 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,783 1,272 3,567 2,545 From Other Comprehensive Income 1 47 32 91 63 Net Periodic Pension Cost 2 $ 1,513 $ 1,470 $ 3,023 $ 2,939 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (77 ) 50 (161 ) 100 Cash flows no December 31, 2017 $20 first 2018. Executive Survivor and Supplemental Retirement Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 72 $ 200 $ 145 Interest Cost on Projected Benefit Obligation 399 421 798 843 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 9 10 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 67 72 134 143 From Other Comprehensive Income 1 165 110 330 220 Net Periodic Pension Cost 2 $ 744 $ 689 $ 1,489 $ 1,378 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in n onservice cost components of postretirement benefits 644 617 1,289 1,233 Postretirement Benefits Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 381 $ 356 $ 763 $ 712 Interest Cost on Projected Benefit Obligation 646 678 1,291 1,356 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 824 466 From Other Comprehensive Income 1 11 6 21 12 Net Periodic Postretirement Benefit Cost 2 $ 1,450 $ 1,273 $ 2,899 $ 2,546 Effect of Medicare Part D Subsidy $ (36 ) $ (140 ) $ (73 ) $ (280 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in n onservice cost components of postretirement benefits 818 738 1,668 1,477

Note 11 - Fair Value of Financi

Note 11 - Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Fair Value Disclosures [Text Block]	1 1 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt June 30, 2018 December 31, 2017 LIBOR 1.50% LIBOR 1.25% Long-Term Debt including Current Maturities 2 820. June 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,036 $ 1,036 $ 16,216 $ 16,216 Short-Term Debt (20,977 ) (20,977 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,127 ) (605,185 ) (490,566 ) (543,691 )

Note 13 - Income Tax Expense -

Note 13 - Income Tax Expense - Continuing Operations	6 Months Ended
	Jun. 30, 2018
Notes to Financial Statements
Income Tax Disclosure [Text Block]	1 3 . Income Tax Expense – Continuing Operations The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 21,750 $ 22,614 $ 51,759 $ 48,506 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 5,655 $ 8,819 $ 13,457 $ 18,917 Increases (Decreases) in Tax from: Property Related Differences and Other Regulatory Adjustments (1,025 ) 35 (2,098 ) 140 Federal Production Tax Credits (930 ) (2,010 ) (2,050 ) (4,062 ) Excess Tax Deduction – Equity Method Stock Awards -- -- (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (213 ) (516 ) (425 ) Research and Development and Other Tax Credits (202 ) (190 ) (409 ) (387 ) Allowance for Funds Used During Construction – Equity (111 ) (91 ) (278 ) (158 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (199 ) (345 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (660 ) Other Items – Net 24 49 96 (63 ) Income Tax Expense – Continuing Operations $ 3,054 $ 5,897 $ 6,848 $ 12,260 Effective Income Tax Rate – Continuing Operations 14.0 % 26.1 % 13.2 % 25.3 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 72 147 Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 712 $ 1,038 The balance of unrecognized tax benefits as of June 30, 2018 June 30, 2018 not 12 no June 30, 2018. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of August 1, 2018, no 2014 The Company recognized the income tax effects of the TCJA in its 2017 No. 118, 740, Income Taxes one December 31, 2017 may may June 30, 2018 not December 31, 2017.

Significant Accounting Policies

Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 six June 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three six June 30, 2018 2017.
Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block]	Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. 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 June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company 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 June 30, 2018 $55.7 35%
Inventory, Policy [Policy Text Block]	Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: June 30, December 31, (in thousands) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034
Goodwill and Intangible Assets, Policy [Policy Text Block]	Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first six 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099
Cash Flow Supplemental [Policy Text Block]	Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01 December 15, 2017, 2016 01 first 2018, ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three six June 30, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. 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. ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $0.8

Note 1 - Summary of Significa21

Note 1 - Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160
Schedule of Inventory, Current [Table Text Block]	June 30, December 31, (in thousands) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034
Schedule of Goodwill [Table Text Block]	(in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572
Schedule of Other Intangible Assets [Table Text Block]	June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765
Finite-lived Intangible Assets Amortization Expense [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	(in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312

Note 2 - Segment Information (T

Note 2 - Segment Information (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 89,400 $ 86,679 $ 198,580 $ 193,133 Changes in Accrued ARP Revenues (1,565 ) (424 ) (2,440 ) (1,663 ) Total Retail Sales Revenue 87,835 86,255 196,140 191,470 Wholesale Revenues – Company Generation 2,539 1,184 3,554 2,051 Other Revenues 13,351 14,797 26,996 27,266 Total Electric Segment Revenues $ 103,725 $ 102,236 $ 226,690 $ 220,787 Manufacturing Segment: Metal Parts and Tooling $ 57,388 $ 49,450 $ 114,315 $ 97,528 Plastic Products and Tooling 7,961 7,376 18,196 16,928 Other 2,805 2,478 4,305 3,265 Total Manufacturing Segment Revenues $ 68,154 $ 59,304 $ 136,816 $ 117,721 Plastics Segment – Sale of PVC Pipe Products $ 54,476 $ 50,551 $ 104,129 $ 87,708 Intersegment Eliminations $ (7 ) $ (5 ) $ (21 ) $ (13 ) Total $ 226,348 $ 212,086 $ 467,614 $ 426,203 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,687 $ 6,439 $ 13,077 $ 12,825 Manufacturing 555 553 1,109 1,107 Plastics 160 173 310 326 Corporate and Intersegment Eliminations 274 362 552 731 Total $ 7,676 $ 7,527 $ 15,048 $ 14,989 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 611 $ 2,442 $ 2,709 $ 8,504 Manufacturing 1,018 1,573 2,241 2,628 Plastics 2,207 2,858 4,621 4,248 Corporate (782 ) (976 ) (2,723 ) (3,120 ) Total $ 3,054 $ 5,897 $ 6,848 $ 12,260 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 10,600 $ 10,134 $ 27,268 $ 25,694 Manufacturing 3,583 2,955 7,747 5,127 Plastics 6,229 4,637 13,073 7,074 Corporate (1,716 ) (1,009 ) (3,177 ) (1,649 ) Discontinued Operations -- 61 -- 117 Total $ 18,696 $ 16,778 $ 44,911 $ 36,363 June 30, December 31, (in thousands) 2018 2017 Electric $ 1,687,799 $ 1,690,224 Manufacturing 181,094 167,023 Plastics 99,205 87,230 Corporate 43,149 59,801 Total $ 2,011,247 $ 2,004,278

Note 3 - Rate and Regulatory 23

Note 3 - Rate and Regulatory Matters (Tables)	6 Months Ended
	Jun. 30, 2018
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 2017 Incentive and Cost Recovery R – March 30, 2018 October 1, 2018 $ 10,300 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2018 Annual Update R – July 3, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2018 Annual Update R – June 14, 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 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh
Schedule of Revenues Recorded under Rate Riders [Table Text Block]	Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,368 $ 2,102 $ 4,884 $ 4,068 Transmission Cost Recovery (458 ) 1,273 (487 ) 3,443 Environmental Cost Recovery (18 ) 2,812 (49 ) 5,636 Renewable Resource Recovery 659 -- 1,184 -- North Dakota Renewable Resource Adjustment 2,079 1,839 4,046 3,609 Transmission Cost Recovery 1,165 1,384 3,227 3,895 Environmental Cost Recovery 1,830 2,388 3,651 4,876 South Dakota Transmission Cost Recovery 250 287 786 728 Environmental Cost Recovery 515 545 1,035 1,142 Conservation Improvement Program Costs and Incentives 122 176 351 416 Total $ 8,512 $ 12,806 $ 18,628 $ 27,813

Note 4 - Regulatory Assets an24

Note 4 - Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Regulatory Assets and Liabilities [Table Text Block]	June 30, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 107,946 $ 117,036 see below Conservation Improvement Program Costs and Incentives 2 3,927 4,163 8,090 27 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,907 6,907 asset lives Deferred Marked-to-Market Losses 1 2,862 1,574 4,436 30 Big Stone II Unrecovered Project Costs – Minnesota 1 665 1,296 1,961 34 Debt Reacquisition Premiums 1 231 856 1,087 171 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 513 -- 513 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 392 492 59 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 422 422 asset lives North Dakota Deferred Rate Case Expenses Subject to Recovery 1 303 -- 303 12 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 223 -- 223 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 75 75 18 Total Regulatory Assets $ 17,914 $ 123,631 $ 141,545 Regulatory Liabilities: Deferred Income Taxes $ -- $ 147,858 $ 147,858 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 79,835 79,835 asset lives Refundable Fuel Clause Adjustment Revenues 4,972 -- 4,972 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 716 -- 716 4 North Dakota Renewable Resource Recovery Rider Accrued Refund 394 -- 394 9 North Dakota Transmission Cost Recovery Rider Accrued Refund 319 -- 319 12 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker -- 316 316 see below South Dakota Environmental Cost Recovery Rider Accrued Refund 308 -- 308 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 240 -- 240 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 231 -- 231 12 Other 6 81 87 186 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 61 24 85 18 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 49 49 see below Minnesota Renewable Resource Recovery Rider Accrued Refund 1 -- 1 4 Total Regulatory Liabilities $ 7,248 $ 228,163 $ 235,411 Net Regulatory Asset/(Liability) Position $ 10,666 $ (104,532 ) $ (93,866 ) December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 )

Note 5 - Reconciliation of Co25

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Stockholders Equity [Table Text Block]	(in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 767 (860 ) (93 ) Common Stock Retirements (297 ) (2,153 ) (2,450 ) Net Income 44,911 44,911 Other Comprehensive Loss (340 ) (340 ) Employee Stock Incentive Plans Expense 2,253 2,253 Common Dividends ($0.67 per share) (26,592 ) (26,592 ) Balance, June 30, 2018 $ 198,257 $ 342,690 $ 179,605 $ (5,971 ) $ 714,581
Schedule of Common Stock Outstanding Roll Forward [Table Text Block]	Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 19,950 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (59,431 ) Common Shares Outstanding, June 30, 2018 39,651,436
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Three Months ended June 30 Six Months ended June 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,605,717 39,462,865 39,578,296 39,406,834 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 202,643 173,974 212,902 187,806 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,616 50,087 58,373 53,980 Nonvested Restricted Shares 10,733 12,719 19,188 19,894 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,360 2,854 2,617 3,098 Total Dilutive Shares 273,352 239,634 293,080 264,778 Weighted Average Common Shares Outstanding – Diluted 39,879,069 39,702,499 39,871,376 39,671,612

Note 6 - Share-based Payments (

Note 6 - Share-based Payments (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted to Executive Officers February 5, 2018 54,000 $ 35.73 December 31, 2020 Restricted Stock Units Granted to Executive Officers February 5, 2018 15,200 $ 41.325 25% per year through February 6, 2022 Restricted Stock Units Granted to Key Employees April 9, 2018 12,945 $ 38.45 100% on April 8, 2022 Restricted Stock Units Granted to Key Employee June 20, 2018 1,000 $ 42.46 100% on April 8, 2022 Restricted Stock Granted to Nonemployee Directors April 9, 2018 18,200 $ 43.40 33% per year through April 8, 2021
Share-based Compensation, Activity [Table Text Block]	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 668 $ 425 $ 1,319 $ 1,074 Restricted Stock Units Granted to Executive Officers 173 104 422 368 Restricted Stock Granted to Executive Officers -- 16 16 38 Restricted Stock Granted to Nonemployee Directors 165 144 331 272 Restricted Stock Units Granted to Key Employees 101 81 165 168 Totals $ 1,107 $ 770 $ 2,253 $ 1,920

Note 9 - Short-term and Long-27

Note 9 - Short-term and Long-term Borrowings (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Line of Credit Facilities [Table Text Block]	(in thousands) Line Limit In Use on June 30, 2018 Restricted due to Outstanding Letters of Credit Available on June 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,102 $ -- $ 123,898 $ 130,000 OTP Credit Agreement 170,000 14,875 300 154,825 57,329 Total $ 300,000 $ 20,977 $ 300 $ 278,723 $ 187,329
Schedule of Debt [Table Text Block]	June 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 14,875 $ 6,102 $ 20,977 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, fully repaid April 1, 2018 -- -- PACE Note, 2.54%, due March 18, 2021 604 604 Total $ 512,000 $ 80,604 $ 592,604 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 167 167 Unamortized Long-Term Debt Issuance Costs 2,045 432 2,477 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,955 $ 80,005 $ 589,960 Total Short-Term and Long-Term Debt (with current maturities) $ 524,830 $ 86,274 $ 611,104 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937

Note 10 - Pension Plan and Ot28

Note 10 - Pension Plan and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 3,230 $ 2,814 Interest Cost on Projected Benefit Obligation 3,363 3,536 6,726 7,070 Expected Return on Assets (5,299 ) (4,807 ) (10,599 ) (9,614 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 29 8 59 From Other Comprehensive Income 1 -- 1 -- 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,783 1,272 3,567 2,545 From Other Comprehensive Income 1 47 32 91 63 Net Periodic Pension Cost 2 $ 1,513 $ 1,470 $ 3,023 $ 2,939 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (77 ) 50 (161 ) 100 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 72 $ 200 $ 145 Interest Cost on Projected Benefit Obligation 399 421 798 843 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 9 10 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 67 72 134 143 From Other Comprehensive Income 1 165 110 330 220 Net Periodic Pension Cost 2 $ 744 $ 689 $ 1,489 $ 1,378 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in n onservice cost components of postretirement benefits 644 617 1,289 1,233 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 381 $ 356 $ 763 $ 712 Interest Cost on Projected Benefit Obligation 646 678 1,291 1,356 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 824 466 From Other Comprehensive Income 1 11 6 21 12 Net Periodic Postretirement Benefit Cost 2 $ 1,450 $ 1,273 $ 2,899 $ 2,546 Effect of Medicare Part D Subsidy $ (36 ) $ (140 ) $ (73 ) $ (280 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in n onservice cost components of postretirement benefits 818 738 1,668 1,477

Note 11 - Fair Value of Finan29

Note 11 - Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Fair Value, by Balance Sheet Grouping [Table Text Block]	June 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,036 $ 1,036 $ 16,216 $ 16,216 Short-Term Debt (20,977 ) (20,977 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,127 ) (605,185 ) (490,566 ) (543,691 )

Note 13 - Income Tax Expense 30

Note 13 - Income Tax Expense - Continuing Operations (Tables)	6 Months Ended
	Jun. 30, 2018
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 21,750 $ 22,614 $ 51,759 $ 48,506 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 5,655 $ 8,819 $ 13,457 $ 18,917 Increases (Decreases) in Tax from: Property Related Differences and Other Regulatory Adjustments (1,025 ) 35 (2,098 ) 140 Federal Production Tax Credits (930 ) (2,010 ) (2,050 ) (4,062 ) Excess Tax Deduction – Equity Method Stock Awards -- -- (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (213 ) (516 ) (425 ) Research and Development and Other Tax Credits (202 ) (190 ) (409 ) (387 ) Allowance for Funds Used During Construction – Equity (111 ) (91 ) (278 ) (158 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (199 ) (345 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (660 ) Other Items – Net 24 49 96 (63 ) Income Tax Expense – Continuing Operations $ 3,054 $ 5,897 $ 6,848 $ 12,260 Effective Income Tax Rate – Continuing Operations 14.0 % 26.1 % 13.2 % 25.3 %
Summary of Income Tax Contingencies [Table Text Block]	(in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 72 147 Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 712 $ 1,038

Note 1 - Summary of Significa31

Note 1 - Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2019USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Goodwill, Period Increase (Decrease), Total		$ 0
Pro Forma [Member] | Accounting Standards Update 2017-07 [Member]
Postretirement Benefit Plan, Nonservice Costs Capitalized to Plant in Service During Fiscal Year			$ 800
Postretirement Benefit Plan, Nonservice Costs Included in Operating Expense During Fiscal Year			$ 5,600	$ 5,100
Scenario, Forecast [Member] | Accounting Standards Update 2018-02 [Member]
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 800
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		$ 55,700
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage		35.00%
Plastics [Member]
Number of Customers Under Build and Hold Agreements		1
Goodwill, Period Increase (Decrease), Total

Note 1 - Summary of Significa32

Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 1 [Member]
Total Assets	$ 2,178	$ 2,108
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Investments	1,233	1,285
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member]
Investments
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Other Assets	945	823
Fair Value, Inputs, Level 2 [Member]
Total Assets	7,157	7,160
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Investments	5,630	5,373
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments	1,527	1,787
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member]
Other Assets

Note 1 - Summary of Significa33

Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Finished Goods	$ 27,140	$ 26,605
Work in Process	17,000	14,222
Raw Material, Fuel and Supplies	46,295	47,207
Total Inventories	$ 90,435	$ 88,034

Note 1 - Summary of Significa34

Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Gross Balance		$ 37,572
Accumulated Impairments
Balance	$ 37,572	37,572
Adjustments to Goodwill	0
Manufacturing [Member]
Gross Balance		18,270
Accumulated Impairments
Balance	18,270	18,270
Adjustments to Goodwill
Plastics [Member]
Gross Balance		19,302
Accumulated Impairments
Balance	19,302	$ 19,302
Adjustments to Goodwill

Note 1 - Summary of Significa35

Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Gross Carrying Amount	$ 23,235	$ 23,235
Accumulated Amortization	10,160	9,470
Net Carrying Amount	13,075	13,765
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	9,560	8,994
Net Carrying Amount	$ 12,931	$ 13,497
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	1 year 180 days	2 years
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	17 years 60 days	17 years 240 days
Covenant Not to Compete [Member]
Gross Carrying Amount	$ 590	$ 590
Accumulated Amortization	557	459
Net Carrying Amount	$ 33	$ 131
Remaining Amortization Periods (Month)	60 days	240 days
Other Intangible Assets [Member]
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	43	17
Net Carrying Amount	$ 111	$ 137
Remaining Amortization Periods (Month)	2 years 60 days	2 years 240 days

Note 1 - Summary of Significa36

Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Amortization Expense – Intangible Assets	$ 345	$ 333	$ 690	$ 665

Note 1 - Summary of Significa37

Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Jun. 30, 2018USD ($)
2,018	$ 1,315
2,019	1,184
2,020	1,133
2,021	1,099
2,022	$ 1,099

Note 1 - Summary of Significa38

Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Jun. 30, 2017
Transactions Related to Capital Additions not Settled in Cash	$ 11,564	$ 16,312

Note 2 - Segment Information (D

Note 2 - Segment Information (Details Textual)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Number of Reportable Segments			3
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Electric [Member]
Number of Customers					1
Concentration Risk, Percentage					11.70%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member]
Number of Customers					1
Concentration Risk, Percentage					24.30%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member]
Number of Customers					1
Concentration Risk, Percentage					12.00%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member]
Number of Customers					2
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer One [Member]
Concentration Risk, Percentage					20.60%
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer Two [Member]
Concentration Risk, Percentage					17.80%
Sales Revenue, Net [Member] | UNITED STATES
Concentration Risk, Percentage	98.20%	98.30%	98.30%	98.30%

Note 2 - Segment Information -

Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Operating Revenues	$ 226,348	$ 212,086	$ 467,614	$ 426,203
Interest charges	7,676	7,527	15,048	14,989
Income Taxes	3,054	5,897	6,848	12,260
Net Income (Loss)	18,696	16,778	44,911	36,363
Assets	2,011,247		2,011,247		$ 2,004,278
Discontinued Operations [Member]
Net Income (Loss)		61		117
Operating Segments [Member] | Electric [Member]
Revenue from Contracts with Customers	13,351	14,797	26,996	27,266
Regulated operating revenues	103,725	102,236	226,690	220,787
Interest charges	6,687	6,439	13,077	12,825
Income Taxes	611	2,442	2,709	8,504
Net Income (Loss)	10,600	10,134	27,268	25,694
Assets	1,687,799		1,687,799		1,690,224
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	89,400	86,679	198,580	193,133
Changes in Accrued ARP Revenues	(1,565)	(424)	(2,440)	(1,663)
Regulated operating revenues	87,835	86,255	196,140	191,470
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	2,539	1,184	3,554	2,051
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	68,154	59,304	136,816	117,721
Interest charges	555	553	1,109	1,107
Income Taxes	1,018	1,573	2,241	2,628
Net Income (Loss)	3,583	2,955	7,747	5,127
Assets	181,094		181,094		167,023
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	57,388	49,450	114,315	97,528
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	7,961	7,376	18,196	16,928
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	2,805	2,478	4,305	3,265
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	54,476	50,551	104,129	87,708
Interest charges	160	173	310	326
Income Taxes	2,207	2,858	4,621	4,248
Net Income (Loss)	6,229	4,637	13,073	7,074
Assets	99,205		99,205		87,230
Corporate and Eliminations [Member]
Interest charges	274	362	552	731
Income Taxes	(782)	(976)	(2,723)	(3,120)
Net Income (Loss)	(1,716)	(1,009)	(3,177)	(1,649)
Assets	43,149		43,149		$ 59,801
Intersegment Eliminations [Member]
Regulated operating revenues	$ (7)	$ (5)	$ (21)	$ (13)

Note 3 - Rate and Regulatory 41

Note 3 - Rate and Regulatory Matters (Details Textual)

Nov. 01, 2018USD ($)

Jul. 06, 2018USD ($)

Apr. 20, 2018USD ($)

Mar. 23, 2018USD ($)

Mar. 22, 2018USD ($)

Dec. 20, 2017USD ($)

Nov. 17, 2017USD ($)

Nov. 01, 2017USD ($)

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, 2018USD ($)

Jun. 30, 2018USD ($)

Dec. 31, 2018

Dec. 31, 2017USD ($)

Jul. 03, 2018USD ($)

Jun. 13, 2018USD ($)

Mar. 01, 2018USD ($)

Nov. 02, 2017USD ($)

Oct. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Apr. 16, 2016

Apr. 15, 2016

Nov. 25, 2009USD ($)

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

35.00%

Minnesota [Member]

Accrued Refund Liabilities Resulting from Tax Rate Reduction

$ 4,100,000

NORTH DAKOTA

Accrued Refund Liabilities Resulting from Tax Rate Reduction

800,000

South Dakota [Member]

Accrued Refund Liabilities Resulting from Tax Rate Reduction

700,000

Scenario, Forecast [Member]

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]

Contract with Customer, Refund Liability, Total

1,600,000

$ 2,700,000

Current Return on Equity Used in Transmission Rates

10.32%

12.38%

10.32%

Proposed Reduced Return on Equity Used in Transmission Rates

8.67%

9.15%

9.70%

Additional Incentive Basis Point

0.50%

Expected Percentage of Return on Equity

10.82%

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]

Estimated Interim Rate Refund

$ 9,000,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member]

Percentage of Allowed Rate of Return on Rate Base

7.5056%

8.61%

Percentage of Allowed Rate of Return on Equity

9.41%

10.74%

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Environmental Cost Recovery Rider [Member] | The 2016 General Rate Case [Member]

Revenues Collected Under Riders, Subject to Customer Refund

$ 900,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member]

Amount Credited to Customers, Subject to Recovery Should the Courts Decision Be Upheld

2,000,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member] | The 2016 General Rate Case [Member]

Revenues Collected Under Riders, Subject to Customer Refund

$ 1,400,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | ECR and TCR Riders [Member] | The 2016 General Rate Case [Member]

Revenues Collected Under Riders, Subject to Refund, Period of Refund

1 year

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member]

Utility Incentive Percentage in Next Rolling Twelve Months

13.50%

Utility Incentive Percentage in Next Rolling Year Two

12.00%

Utility Incentive Percentage in Next Rolling Year Three

10.00%

Assumed Savings of Utility

1.70%

Financial Incentive, Maximum Percentage of Spending, Year One

40.00%

Financial Incentive, Maximum Percentage of Spending, Year Two

35.00%

Financial Incentive, Maximum Percentage of Spending, Year Three

30.00%

Financial Incentives Recognized During Period

$ 2.60

$ 2,600,000

Percentage Decrease in Energy Savings

10.00%

Amount Of Financial Incentive Requested

$ 2,900,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member]

Amount Of Financial Incentive Requested

$ 2,600,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Renewable Resource Adjustment [Member]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 1,300,000

Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Renewable Resource Adjustment [Member] | Scenario, Forecast [Member]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 5,800,000

Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member]

Percentage of Allowed Rate of Return on Rate Base

7.97%

Percentage of Allowed Rate of Return on Equity

10.30%

10.30%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 7,100,000

$ 13,100,000

General Rate Revenue Increase Requested

$ 13,100,000

Percentage of Increase in Base Rate Revenue Requested

8.72%

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 12,800,000

Public Utilities, Interim Rate Requirement, Decrease in Amount

$ 4,500,000

Public Utilities, Interim Rate Requirement, Amount

$ 8,300,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

4.80%

General Rate Revenue Increase Requested, Decrease

$ 6,000,000

General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform

4,800,000

General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform

$ 1,200,000

Contract with Customer, Refund Liability, Total

$ 1,800,000

Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member] | Subsequent Event [Member]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 5,400,000

Percentage of Requested Allowed Rate of Return on Equity

9.77%

Equity to Total Capitalization Ratio Basis for Return on Equity

52.50%

Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2008 General Rate Case [Member]

Percentage of Allowed Rate of Return on Rate Base

8.62%

Percentage of Allowed Rate of Return on Equity

10.75%

General Rate Revenue Increase Requested

$ 3,600,000

Percentage of Increase in Base Rate Revenue Requested

3.00%

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%

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]

Expanded Capacity of Projects

345

Extended Distance of Transmission Line

163

Current Projected Cost

$ 99,400,000

Percentage of Assets of Project

100.00%

Otter Tail Power Company [Member] | Big Stone South - Brookings MVP [Member]

Expanded Capacity of Projects

345

Extended Distance of Transmission Line

70

Current Projected Cost

$ 72,500,000

Percentage of Assets of Project

100.00%

Note 3 - Rate and Regulatory 42

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	6 Months Ended
	Jun. 30, 2018USD ($)kWh
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
R - Request Date	Mar. 30, 2018
Effective Date Requested or Approved	Oct. 1, 2018
Annual Revenue	$ 10,300
Rate rider rate (Kilowatt-Hour) | kWh	0.006
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Oct. 1, 2017
Annual Revenue	$ 9,868
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
A - Approval Date	Sep. 15, 2017
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2015 Incentive and Cost Recovery [Member]
Effective Date Requested or Approved	Oct. 1, 2016
Annual Revenue	$ 8,590
Rate rider rate (Kilowatt-Hour) | kWh	0.00275
A - Approval Date	Jul. 19, 2016
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Nov. 1, 2017	[1]
Annual Revenue	$ (3,311)	[1]
A - Approval Date	Oct. 30, 2017	[1]
Rate	Various	[1]
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Sep. 1, 2016
Annual Revenue	$ 4,736
A - Approval Date	Jul. 5, 2016
Rate	Various
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Apr. 1, 2016
Annual Revenue	$ 7,203
A - Approval Date	Mar. 9, 2016
Rate	Various
Minnesota [Member] | 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%)
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Sep. 1, 2016
Annual Revenue	$ 11,884
A - Approval Date	Jul. 5, 2016
Rate of base	6.927%
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
R - Request Date	Jul. 3, 2018
Effective Date Requested or Approved	Dec. 1, 2018
Annual Revenue
Rate of base	0.00%
Minnesota [Member] | 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
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
R - Request Date	Jun. 14, 2018
Effective Date Requested or Approved	Nov. 1, 2018
Annual Revenue	$ 5,886
Rate rider rate (Kilowatt-Hour) | kWh	0.00244
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Jan. 1, 2017
Annual Revenue	$ 6,916
A - Approval Date	Dec. 14, 2016
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,469
A - Approval Date	Feb. 27, 2018
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 7,959
A - Approval Date	Nov. 29, 2017
Rate	Various
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 8,537
A - Approval Date	Dec. 20, 2017
Rate of base	6.629%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Jul. 1, 2016
Annual Revenue	$ 10,359
A - Approval Date	Jun. 22, 2016
Rate of base	7.904%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,718
A - Approval Date	Feb. 27, 2018
Rate of base	5.593%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Aug. 1, 2017
Annual Revenue	$ 9,917
A - Approval Date	Jul. 12, 2017
Rate of base	7.633%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 9,989
A - Approval Date	Dec. 20, 2017
Rate of base	7.756%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Apr. 1, 2017
Annual Revenue	$ 9,156
A - Approval Date	Mar. 15, 2017
Rate of base	7.005%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Jul. 1, 2016
Annual Revenue	$ 9,262
A - Approval Date	Jun. 22, 2016
Rate of base	7.573%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 9,650
A - Approval Date	Feb. 27, 2018
Rate of base	7.493%
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Mar. 1, 2017
Annual Revenue	$ 2,053
A - Approval Date	Feb. 17, 2017
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
Effective Date Requested or Approved	Mar. 1, 2016
Annual Revenue	$ 1,895
A - Approval Date	Feb. 12, 2016
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 1,779
A - Approval Date	Feb. 28, 2018
Rate	Various
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
Effective Date Requested or Approved	Nov. 1, 2016
Annual Revenue	$ 2,238
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
A - Approval Date	Oct. 26, 2016
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved	Nov. 1, 2017
Annual Revenue	$ 2,082
Rate rider rate (Kilowatt-Hour) | kWh	0.00483
A - Approval Date	Oct. 13, 2017
[1]	Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

Note 3 - Rate and Regulatory 43

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		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues recorded under rate riders		$ 8,512	$ 12,806	$ 18,628	$ 27,813
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	[1]	2,368	2,102	4,884	4,068
Minnesota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders			1,273		3,443
Revenues recorded under rate riders		(458)		(487)
Minnesota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders			2,812		5,636
Revenues recorded under rate riders		(18)		(49)
Minnesota [Member] | Renewable Resource Cost Recovery Rider [Member]
Revenues recorded under rate riders		659		1,184
North Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,165	1,384	3,227	3,895
North Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,830	2,388	3,651	4,876
North Dakota [Member] | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		2,079	1,839	4,046	3,609
South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders		122	176	351	416
South Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		250	287	786	728
South Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		$ 515	$ 545	$ 1,035	$ 1,142
[1]	Includes MNCIP costs recovered in base rates.

Note 4 - Regulatory Assets an44

Note 4 - Regulatory Assets and Liabilities (Details Textual)	6 Months Ended
	Jun. 30, 2018
Regulatory Noncurrent Asset, Remaining Recovery Period	14 years 90 days

Note 4 - Regulatory Assets an45

Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
		Jun. 30, 2018	Dec. 31, 2017
Regulatory Assets - Current		$ 17,914	$ 22,551
Regulatory Assets - Long -Term		123,631	129,576
Regulatory Assets - Total		141,545	152,127
Regulatory Liabilities - Current		7,248	9,688
Regulatory Liabilities - Long -Term		228,163	232,893
Regulatory Liabilities - Total		235,411	242,581
Net Regulatory Asset Position - Current		10,666	12,863
Net Regulatory Asset Position - Long-Term		(104,532)	(103,317)
Net Regulatory Asset/(Liability) Position		(93,866)	(90,454)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		147,858	149,052
Regulatory Liabilities - Total		$ 147,858	$ 149,052
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		79,835	83,100
Regulatory Liabilities - Total		$ 79,835	$ 83,100
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current		$ 4,972	$ 5,778
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 4,972	$ 5,778
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 716	$ 1,667
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 716	$ 1,667
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		120 days	330 days
North Dakota Renewable Resource Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 394
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 394
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		270 days
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 319	$ 349
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 319	$ 349
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		316
Regulatory Liabilities - Total		$ 316
Regulatory Liabilities - Remaining Recovery/Refund Period		see below
Minnesota Southwest Power Pool Transmission Cost Tracker Refund [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term			609
Regulatory Liabilities - Total			$ 609
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year 300 days
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 308	$ 187
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 308	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 240
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 240
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 231	$ 151
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 231	$ 151
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current		$ 61	$ 132
Regulatory Liabilities - Long -Term		24	48
Regulatory Liabilities - Total		$ 85	$ 180
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 180 days	2 years
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 5
Regulatory Liabilities - Long -Term		81	84
Regulatory Liabilities - Total		$ 87	$ 89
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		15 years 180 days	16 years
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current			$ 208
Regulatory Liabilities - Long -Term		49
Regulatory Liabilities - Total		$ 49	$ 208
Regulatory Liabilities - Remaining Recovery/Refund Period		see below
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			120 days
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 1	$ 409
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 1	$ 409
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		120 days	1 year
Minnesota Transmission Cost Recovery Rider Accrued Refund [member]
Regulatory Liabilities - Current			$ 802
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total			$ 802
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			300 days
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member]
Regulatory Assets - Current	[1]	$ 9,090	$ 9,090
Regulatory Assets - Long -Term	[1]	107,946	112,487
Regulatory Assets - Total	[1]	$ 117,036	$ 121,577
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 3,927	$ 7,385
Regulatory Assets - Long -Term	[2]	4,163	2,774
Regulatory Assets - Total	[2]	$ 8,090	$ 10,159
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	2 years 90 days	1 year 270 days
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	6,907	6,651
Regulatory Assets - Total	[1]	$ 6,907	$ 6,651
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 2,862	$ 4,063
Regulatory Assets - Long -Term	[1]	1,574	2,405
Regulatory Assets - Total	[1]	$ 4,436	$ 6,468
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 180 days	3 years
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 665	$ 650
Regulatory Assets - Long -Term	[1]	1,296	1,636
Regulatory Assets - Total	[1]	$ 1,961	$ 2,286
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 300 days	3 years 120 days
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 231	$ 254
Regulatory Assets - Long -Term	[1]	856	960
Regulatory Assets - Total	[1]	$ 1,087	$ 1,214
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	14 years 90 days	14 years 270 days
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]	$ 513	$ 75
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 513	$ 75
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]	$ 100	$ 100
Regulatory Assets - Long -Term	[1]	392	442
Regulatory Assets - Total	[1]	$ 492	$ 542
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	4 years 330 days	5 years 150 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]	422
Regulatory Assets - Total	[1]	$ 422
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 303	$ 309
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 303	$ 309
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	75	1,985
Regulatory Assets - Total	[1]	$ 75	$ 1,985
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year 180 days	2 years
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 223
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 223
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year 180 days
North Dakota Renewable Resource Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 206
Regulatory Assets - Long -Term	[2]		236
Regulatory Assets - Total	[2]		$ 442
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year 90 days
Minnesota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]		$ 267
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]		$ 267
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]		120 days
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 152
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 152
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year
[1]	Costs subject to recovery excluding a rate of return.
[2]	Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

Note 5 - Reconciliation of Co46

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	May 03, 2018
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Dividend Reinvestment and Share Purchase Plan [Member]
Shelf Registration, Shares					1,500,000

Note 5 - Reconciliation of Co47

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Balance, beginning			$ 696,892
Common Stock Issuances, Net of Expenses			(93)
Common Stock Retirements			(2,450)
Net Income	$ 18,696	$ 16,778	44,911	$ 36,363
Other Comprehensive Loss			(340)
Employee Stock Incentive Plans Expense			2,253
Common Dividends ($0.67 per share)			(26,592)
Balance, ending	714,581		714,581
Par Value, Common Shares [Member]
Balance, beginning			197,787
Common Stock Issuances, Net of Expenses			767
Common Stock Retirements			(297)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($0.67 per share)
Balance, ending	198,257		198,257
Premium on Common Shares [Member]
Balance, beginning			343,450
Common Stock Issuances, Net of Expenses			(860)
Common Stock Retirements			(2,153)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense			2,253
Common Dividends ($0.67 per share)
Balance, ending	342,690		342,690
Retained Earnings [Member]
Balance, beginning			161,286
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income			44,911
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($0.67 per share)			(26,592)
Balance, ending	179,605		179,605
Accumulated Other Comprehensive Income/(Loss) [Member]
Balance, beginning			(5,631)
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Loss			(340)
Employee Stock Incentive Plans Expense
Common Dividends ($0.67 per share)
Balance, ending	$ (5,971)		$ (5,971)

Note 5 - Reconciliation of Co48

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) (Parentheticals) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32	$ 0.67	$ 0.64

Note 5 - Reconciliation of Co49

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	6 Months Ended
	Jun. 30, 2018shares
Common Shares Outstanding, beginning balance (in shares)	39,557,491
Issuances:
Executive Stock Performance Awards (2015 shares earned) (in shares)	114,648
Vesting of Restricted Stock Units (in shares)	19,950
Restricted Stock Issued to Directors (in shares)	18,200
Directors Deferred Compensation (in shares)	578
Retirements:
Shares Withheld for Individual Income Tax Requirements (in shares)	(59,431)
Common Shares Outstanding, ending balance (in shares)	39,651,436

Note 5 - Reconciliation of Co50

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Weighted Average Common Shares Outstanding – Basic (in shares)	39,605,717	39,462,865	39,578,296	39,406,834
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)	202,643	173,974	212,902	187,806
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	57,616	50,087	58,373	53,980
Nonvested Restricted Shares (in shares)	10,733	12,719	19,188	19,894
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,360	2,854	2,617	3,098
Total Dilutive Shares (in shares)	273,352	239,634	293,080	264,778
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,879,069	39,702,499	39,871,376	39,671,612

Note 6 - Share-based Payments51

Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions	Feb. 05, 2018	Jun. 30, 2018
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Total		$ 6.2
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years 73 days
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	54,000
Period Specified for Average Adjusted Return	3 years
Number of Trading Days	20 days
Number of Shares Authorized for Actual Payment	81,000
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member]
Percentage of Target Amount as Actual Payment	0.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member]
Percentage of Target Amount as Actual Payment	150.00%
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,000
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	27,000

Note 6 - Share-based Payments -

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) - The 2014 Stock Incentive Plan [Member]	6 Months Ended
	Jun. 30, 2018$ / sharesshares
Stock Performance Awards [Member] | Executive Officer [Member]
Shares/units granted, grant date	Feb. 5, 2018
Performance Shares [Member] | Executive Officer [Member]
Shares/units granted (in shares) | shares	54,000
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 35.73
Shares/units granted, vesting date	Dec. 31, 2020
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Shares/units granted, grant date	Feb. 5, 2018
Shares/units granted (in shares) | shares	15,200
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 41.325
Shares/units granted, vesting date	Feb. 6, 2022
Restricted Stock Units (RSUs) [Member] | Key Employees [Member]
Shares/units granted, grant date	Apr. 9, 2018
Shares/units granted (in shares) | shares	12,945
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 38.45
Shares/units granted, vesting date	Apr. 8, 2022
Restricted Stock Units (RSUs) [Member] | Key Employee [Member]
Shares/units granted, grant date	Jun. 20, 2018
Shares/units granted (in shares) | shares	1,000
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 42.46
Shares/units granted, vesting date	Apr. 8, 2022
Restricted Stock [Member] | Nonemployee Directors [Member]
Shares/units granted, grant date	Apr. 9, 2018
Shares/units granted (in shares) | shares	18,200
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 43.40
Shares/units granted, vesting date	Apr. 8, 2021

Note 6 - Share-based Payments53

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals) - The 2014 Stock Incentive Plan [Member]	6 Months Ended
	Jun. 30, 2018
Executive Officer [Member] | Restricted Stock Units (RSUs) [Member]
Shares/units granted, vesting percentage	25.00%
Key Employees [Member] | Restricted Stock Units (RSUs) [Member]
Shares/units granted, vesting percentage	100.00%
Key Employee [Member] | Restricted Stock Units (RSUs) [Member]
Shares/units granted, vesting percentage	100.00%
Nonemployee Directors [Member] | Restricted Stock [Member]
Shares/units granted, vesting percentage	33.00%

Note 6 - Share-based Payments54

Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Stock compensation expense	$ 1,107	$ 770	$ 2,253	$ 1,920
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	668	425	1,319	1,074
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	173	104	422	368
Restricted Stock Units (RSUs) [Member] | Key Employees [Member]
Stock compensation expense	101	81	165	168
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense		16	16	38
Restricted Stock [Member] | Nonemployee Directors [Member]
Stock compensation expense	$ 165	$ 144	$ 331	$ 272

Note 7 - Retained Earnings an55

Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($)	May 01, 2018	Jun. 30, 2018	Dec. 31, 2017
Capitalization, Long-term Debt and Equity, Total		$ 1,304,541,000	$ 1,187,272,000
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio		52.50%
Net Assets Restricted from Distribution		$ 473,000,000
Capitalization, Long-term Debt and Equity, Total		$ 1,178,024,000
Otter Tail Power Company [Member] | If Approved [Member]
Capitalization, Long-term Debt and Equity, Total	$ 1,204,416,000
Otter Tail Power Company [Member] | Minimum [Member]
Equity to Total Capitalization Ratio		47.40%
Otter Tail Power Company [Member] | Minimum [Member] | Minnesota Public Utilities Commission [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	47.90%
Otter Tail Power Company [Member] | Maximum [Member]
Equity to Total Capitalization Ratio		58.00%
Otter Tail Power Company [Member] | Maximum [Member] | Minnesota Public Utilities Commission [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	58.50%

Note 8 - Commitments and Cont56

Note 8 - Commitments and Contingencies (Details Textual)	6 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)	Dec. 31, 2017USD ($)
Loss Contingency, Estimate of Possible Loss	$ 1,000,000
Agreement to Lease Rail Cars for Transporting Coal to Hoot Lake Plant [Member]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	216,000
Operating Leases, Future Minimum Payments, Due in Two Years	324,000
Operating Leases, Future Minimum Payments, Due in Three Years	324,000
Operating Leases, Future Minimum Payments, Due in Four Years	162,000
Arrangement To Lease Manufacturing and Warehouse Space in a Building Near the Georgia Plant [Member]
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year	79,000
Operating Leases, Future Minimum Payments, Due in Two Years	322,000
Operating Leases, Future Minimum Payments, Due in Three Years	332,000
Operating Leases, Future Minimum Payments, Due in Four Years	$ 342,000
Lessee, Operating Lease, Term of Contract	5 years 90 days
Operating Leases, Future Minimum Payments, Due in Five Years	$ 352,000
Operating Leases, Future Minimum Payments, Due Thereafter	$ 271,000
Otter Tail Power Company [Member]
Number of Utilities Participating in MISO RSG Proceeding Before FERC	200
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1,600,000
Otter Tail Power Company [Member] | Coal Purchase Commitments 1 [Member]
Contract Expiration Year	2,041
Otter Tail Power Company [Member] | Construction Programs [Member]
Contract Expiration Year	2,019	2,019
Long-term Purchase Commitment, Amount	$ 45,300,000	$ 41,000,000
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2,040
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount	$ 5,800,000	$ 6,700,000

Note 9 - Short-term and Long-57

Note 9 - Short-term and Long-term Borrowings (Details Textual) $ in Billions	Feb. 07, 2018USD ($)
The 2018 Note Purchase Agreement [Member]
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount	10.00%
Debt Instrument, Prepayment, Percentage of the Principal Amount Prepaid	100.00%
Debt Instrument, Percentage of Principal Amount to be Offered for Prepayment in the Event of a Change of Control	100.00%
Otter Tail Power Company [Member] | Series 2018 A senior Unsecured Notes Due February 7, 2048 [Member]
Debt Instrument, Face Amount	$ 0.1
Debt Instrument, Interest Rate, Stated Percentage	4.07%

Note 9 - Short-term and Long-58

Note 9 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Line Limit	$ 300,000
In Use	20,977
Restricted due to Outstanding Letters of Credit	300
Available	278,723	$ 187,329
Otter Tail Corporation Credit Agreement [Member]
Line Limit	130,000
In Use	6,102
Restricted due to Outstanding Letters of Credit
Available	123,898	130,000
OTP Credit Agreement [Member]
Line Limit	170,000
In Use	14,875
Restricted due to Outstanding Letters of Credit	300
Available	$ 154,825	$ 57,329

Note 9 - Short-term and Long-59

Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Short-Term Debt	$ 20,977	$ 112,371
Long-Term Debt	592,604	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	167	186
Unamortized Long-Term Debt Issuance Costs	2,477	2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	589,960	490,380
Total Short-Term and Long-Term Debt (with current maturities)	611,104	602,937
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt		27
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	604	684
Otter Tail Power Company [Member]
Short-Term Debt	14,875	112,371
Long-Term Debt	512,000	412,000
Less: Current Maturities net of Unamortized Debt Issuance Costs
Unamortized Long-Term Debt Issuance Costs	2,045	1,684
Total Long-Term Debt net of Unamortized Debt Issuance Costs	509,955	410,316
Total Short-Term and Long-Term Debt (with current maturities)	524,830	522,687
Otter Tail Power Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Long-Term Debt	42,000	42,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Long-Term Debt	100,000
Otter Tail Power Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt
Parent Company [Member]
Short-Term Debt	6,102
Long-Term Debt	80,604	80,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	167	186
Unamortized Long-Term Debt Issuance Costs	432	461
Total Long-Term Debt net of Unamortized Debt Issuance Costs	80,005	80,064
Total Short-Term and Long-Term Debt (with current maturities)	86,274	80,250
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Parent Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt
Parent Company [Member] | North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt		27
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 604	$ 684

Note 9 - Short-term and Long-60

Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Debt Instrument, Interest Rate, Stated Percentage	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Debt Instrument, Interest Rate, Stated Percentage		0.90%
Long-Term Debt, Due Date		Feb. 5, 2018
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 1, 2021	Dec. 1, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Debt Instrument, Interest Rate, Stated Percentage	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Debt Instrument, Interest Rate, Stated Percentage	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member]
Debt Instrument, Interest Rate, Stated Percentage	4.07%
Long-Term Debt, Due Date	Feb. 7, 2048
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Debt Instrument, Interest Rate, Stated Percentage	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 1, 2018	Apr. 1, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

Note 10 - Pension Plan and Ot61

Note 10 - Pension Plan and Other Postretirement Benefits (Details Textual) - Pension Plan [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Minimum Funding Requirement		$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 20,000

Note 10 - Pension Plan and Ot62

Note 10 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,615	$ 1,407	$ 3,230	$ 2,814
Interest Cost on Projected Benefit Obligation		3,363	3,536	6,726	7,070
Expected Return on Assets		(5,299)	(4,807)	(10,599)	(9,614)
From Regulatory Asset		4	29	8	59
From Other Comprehensive Income	[1]		1		2
From Regulatory Asset		1,783	1,272	3,567	2,545
From Other Comprehensive Income	[1]	47	32	91	63
Net Periodic Pension Cost	[2]	1,513	1,470	3,023	2,939
From Other Comprehensive Income	[1]	47	32	91	63
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		379	286	707	571
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		1,195	1,100	2,442	2,200
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		40	34	80	68
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		(24)		(45)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		(77)	50	(161)	100
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		100	72	200	145
Interest Cost on Projected Benefit Obligation		399	421	798	843
From Regulatory Asset		4	4	8	8
From Other Comprehensive Income	[3]	9	10	19	19
From Regulatory Asset		67	72	134	143
From Other Comprehensive Income	[3]	165	110	330	220
Net Periodic Pension Cost	[4]	744	689	1,489	1,378
From Other Comprehensive Income	[3]	165	110	330	220
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		25	23	50	47
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		75	49	150	98
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		644	617	1,289	1,233
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		381	356	763	712
Interest Cost on Projected Benefit Obligation		646	678	1,291	1,356
From Regulatory Asset		412	233	824	466
From Other Comprehensive Income	[1]	11	6	21	12
Net Periodic Pension Cost	[5]	1,450	1,273	2,899	2,546
Effect of Medicare Part D Subsidy		(36)	(140)	(73)	(280)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		89	248	167	495
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		283	279	577	557
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		9	8	19	17
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		251		468
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		$ 818	$ 738	$ 1,668	$ 1,477
[1]	Corporate cost included in nonservice cost components of postretirement benefits.
[2]	Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in nonservice cost components of postretirement benefits (77 ) 50 (161 ) 100
[3]	Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company's consolidated statements of income.
[4]	Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in nonservice cost components of postretirement benefits 644 617 1,289 1,233
[5]	Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in nonservice cost components of postretirement benefits 818 738 1,668 1,477

Note 11 - Fair Value of Finan63

Note 11 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Otter Tail Corporation Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.50%	1.50%
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR
OTP Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.25%	1.25%
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR

Note 11 - Fair Value of Finan64

Note 11 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 1,036	$ 16,216
Short-Term Debt	(20,977)	(112,371)
Long-Term Debt including Current Maturities	(590,127)	(490,566)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	1,036	16,216
Short-Term Debt	(20,977)	(112,371)
Long-Term Debt including Current Maturities	$ (605,185)	$ (543,691)

Note 13 - Income Tax Expense 65

Note 13 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)
Period for Unrecognized Tax Benefits Not Expected Change	1 year
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ 0

Note 13 - Income Tax Expense 66

Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Before Income Taxes – Continuing Operations	$ 21,750	$ 22,614	$ 51,759	$ 48,506
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017)	5,655	8,819	13,457	18,917
Increases (Decreases) in Tax from:
Property Related Differences and Other Regulatory Adjustments	(1,025)	35	(2,098)	140
Federal Production Tax Credits	(930)	(2,010)	(2,050)	(4,062)
Excess Tax Deduction – Equity Method Stock Awards			(624)	(697)
Other Comprehensive Income Deferred Tax Rate Adjustment			(531)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(213)	(516)	(425)
Research and Development and Other Tax Credits	(202)	(190)	(409)	(387)
Allowance for Funds Used During Construction – Equity	(111)	(91)	(278)	(158)
Employee Stock Ownership Plan Dividend Deduction	(99)	(172)	(199)	(345)
Section 199 Domestic Production Activities Deduction		(330)		(660)
Other Items – Net	24	49	96	(63)
Income Tax Expense – Continuing Operations	$ 3,054	$ 5,897	$ 6,848	$ 12,260
Effective Income Tax Rate – Continuing Operations	14.00%	26.10%	13.20%	25.30%

Note 13 - Income Tax Expense 67

Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Composite Federal and State Statutory Rate	26.00%	39.00%	26.00%	39.00%

Note 13 - Income Tax Expense 68

Note 13 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Balance, beginning	$ 684	$ 891
Decreases Related to Tax Positions for Prior Years	(44)
Increases Related to Tax Positions for Current Year	72	147
Uncertain Positions Resolved During Year
Balance, ending	$ 712	$ 1,038