Otter Tail (OTTR) 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 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 Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		39,664,884
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Amendment Flag	false

Consolidated Balance Sheets (Cu

Consolidated Balance Sheets (Current Period Not Audited) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and Cash Equivalents	$ 649	$ 16,216
Accounts Receivable:
Trade—Net	96,095	68,466
Other	8,036	7,761
Inventories	94,615	88,034
Unbilled Receivables	16,855	22,427
Income Taxes Receivable		1,181
Regulatory Assets	16,552	22,551
Other	8,611	12,491
Total Current Assets	241,413	239,127
Investments	9,123	8,629
Other Assets	36,721	36,006
Goodwill	37,572	37,572
Other Intangibles—Net	12,746	13,765
Regulatory Assets	124,553	129,576
Plant
Electric Plant in Service	2,000,313	1,981,018
Nonelectric Operations	225,620	216,937
Construction Work in Progress	183,397	141,067
Total Gross Plant	2,409,330	2,339,022
Less Accumulated Depreciation and Amortization	844,042	799,419
Net Plant	1,565,288	1,539,603
Total Assets	2,027,416	2,004,278
Current Liabilities
Short-Term Debt	15,489	112,371
Current Maturities of Long-Term Debt	169	186
Accounts Payable	91,033	84,185
Accrued Salaries and Wages	21,486	21,534
Accrued Federal and State Income Taxes	2,708
Other Accrued Taxes	15,269	16,808
Regulatory Liabilities	7,926	9,688
Other Accrued Liabilities	9,373	11,389
Liabilities of Discontinued Operations		492
Total Current Liabilities	163,453	256,653
Pensions Benefit Liability	89,139	109,708
Other Postretirement Benefits Liability	70,703	69,774
Other Noncurrent Liabilities	25,889	22,769
Commitments and Contingencies (note 8)
Deferred Credits
Deferred Income Taxes	108,699	100,501
Deferred Tax Credits	20,325	21,379
Regulatory Liabilities - Long -Term	231,594	232,893
Other	2,328	3,329
Total Deferred Credits	362,946	358,102
Capitalization
Long-Term Debt—Net	589,984	490,380
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2018—39,664,884 Shares; 2017—39,557,491 Shares	198,324	197,787
Premium on Common Shares	343,210	343,450
Retained Earnings	189,575	161,286
Accumulated Other Comprehensive Loss	(5,807)	(5,631)
Total Common Equity	725,302	696,892
Total Capitalization	1,315,286	1,187,272
Total Liabilities and Equity	2,027,416	2,004,278
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares

Consolidated Balance Sheets (_2

Consolidated Balance Sheets (Current Period Not Audited) (Parentheticals) - $ / shares	Sep. 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)	39,664,884	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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues:
Total Operating Revenues	$ 227,662	$ 216,457	$ 695,276	$ 642,660
Operating Expenses
Production Fuel – Electric	17,129	16,096	51,723	44,955
Cost of Products Sold (depreciation included below)	93,361	86,230	275,691	245,520
Electric Operation and Maintenance Expenses	33,897	35,469	111,113	109,494
Other Nonelectric Expenses	12,547	10,631	37,690	30,625
Depreciation and Amortization	18,708	17,927	56,216	53,689
Property Taxes – Electric	4,094	3,721	11,202	11,228
Total Operating Expenses	189,400	183,445	589,294	544,446
Operating Income	38,262	33,012	105,982	98,214
Interest Charges	7,549	7,393	22,597	22,382
Nonservice Cost Components of Postretirement Benefits	1,326	1,403	4,129	4,215
Other Income	1,245	592	3,135	1,697
Income Before Income Taxes – Continuing Operations	30,632	24,808	82,391	73,314
Income Tax Expense – Continuing Operations	7,359	7,035	14,207	19,295
Net Income from Continuing Operations	23,273	17,773	68,184	54,019
Discontinued Operations
(Loss) Income – net of Income Tax (Savings) Expense of $0, ($25), $0 and $53 for the respective periods		(39)		78
Net Income	$ 23,273	$ 17,734	$ 68,184	$ 54,097
Average Number of Common Shares Outstanding – Basic (in shares)	39,621,524	39,507,581	39,592,705	39,440,416
Average Number of Common Shares Outstanding – Diluted (in shares)	39,903,565	39,795,366	39,882,105	39,712,862
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 0.59	$ 0.45	$ 1.72	$ 1.37
Discontinued Operations (in dollars per share)
(in dollars per share)	0.59	0.45	1.72	1.37
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	0.58	0.45	1.71	1.36
Discontinued Operations (in dollars per share)
(in dollars per share)	0.58	0.45	1.71	1.36
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32	$ 1.005	$ 0.96
Electricity [Member]
Operating Revenues:
Revenues from Contracts with Customers	$ 105,749	$ 102,923	$ 334,858	$ 325,360
Changes in Accrued Revenues under Alternative Revenue Programs	(317)	471	(2,757)	(1,192)
Operating Revenues	105,432	103,394	332,101	324,168
Product [Member]
Operating Revenues:
Revenues from Contracts with Customers	122,230	113,063	363,175	318,492
Electricity, Purchased [Member]
Operating Expenses
Cost of Products Sold (depreciation included below)	$ 9,664	$ 13,371	$ 45,659	$ 48,935

Consolidated Statements of In_2

Consolidated Statements of Income (Not Audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Expense - Discontinued Operations	$ 0	$ (25)	$ 0	$ 53

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income	$ 23,273	$ 17,734	$ 68,184	$ 54,097
Unrealized (Losses) Gains on Available-for-Sale Securities:
Reversal of Previously Recognized Losses (Gains) Realized on Sale of Investments and Included in Other Income During Period	4	(1)	(106)	(2)
Unrealized (Losses) Gains Arising During Period	(14)	52	(93)	90
Income Tax Benefit (Expense)	2	(18)	42	(31)
Change in Unrealized (Losses) Gains on Available-for-Sale Securities – net-of-tax	(8)	33	(157)	57
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10)	232	157	692	473
Income Tax Expense	(60)	(63)	(180)	(189)
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act			(531)
Pension and Postretirement Benefit Plans – net-of-tax	172	94	(19)	284
Total Other Comprehensive Income (Loss)	164	127	(176)	341
Total Comprehensive Income	$ 23,437	$ 17,861	$ 68,008	$ 54,438

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash Flows from Operating Activities
Net Income	$ 68,184	$ 54,097
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		(78)
Depreciation and Amortization	56,216	53,689
Deferred Tax Credits	(1,054)	(1,102)
Deferred Income Taxes	7,529	15,680
Change in Deferred Debits and Other Assets	10,641	7,875
Discretionary Contribution to Pension Plan	(20,000)
Change in Noncurrent Liabilities and Deferred Credits	(191)	1,788
Allowance for Equity/Other Funds Used During Construction	(1,586)	(636)
Stock Compensation Expense—Equity Awards	3,402	2,765
Other—Net	(201)	99
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(27,804)	(21,122)
Change in Inventories	(6,581)	4,825
Change in Other Current Assets	3,827	3,079
Change in Payables and Other Current Liabilities	5,746	(5,153)
Change in Interest and Income Taxes Receivable/Payable	2,932	(1,595)
Net Cash Provided by Continuing Operations	101,060	114,211
Net Cash Used in Discontinued Operations	(200)	(134)
Net Cash Provided by Operating Activities	100,860	114,077
Cash Flows from Investing Activities
Capital Expenditures	(74,489)	(94,549)
Net Proceeds from Disposal of Noncurrent Assets	1,879	2,456
Cash Used for Investments and Other Assets	(3,324)	(3,158)
Net Cash Used in Investing Activities	(75,934)	(95,251)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	(7)	4,826
Net Short-Term (Repayments) Borrowings	(96,882)	60,754
Proceeds from Issuance of Common Stock		4,349
Common Stock Issuance Expenses	(108)
Payments for Retirement of Capital Stock	(3,012)	(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	(148)	(48,172)
Dividends Paid	(39,895)	(37,958)
Net Cash Used in Financing Activities	(40,493)	(18,000)
Net Change in Cash and Cash Equivalents	(15,567)	826
Cash and Cash Equivalents at Beginning of Period	16,216
Cash and Cash Equivalents at End of Period	$ 649	$ 826

Note 1 - Summary of Significant

Note 1 - Summary of Significant Accounting Policies	9 Months Ended
	Sep. 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 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 nine September 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 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 September 30, 2018 December 31, 2017: September 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,373 Corporate Debt Securities – Held by Captive Insurance Company $ 6,012 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 776 Total Assets $ 2,149 $ 7,539 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 September 30, 2018 $54.8 35% Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2018 2017 Finished Goods $ 28,907 $ 26,605 Work in Process 19,124 14,222 Raw Material, Fuel and Supplies 46,584 47,207 Total Inventories $ 94,615 $ 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 nine 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) September 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 September 30, 2018 December 31, 2017: September 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,843 $ 12,648 15 - 203 Other 154 56 98 23 Total $ 22,645 $ 9,899 $ 12,746 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 Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 329 $ 336 $ 1,019 $ 1,001 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 September 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 12,059 $ 17,940 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. 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 nine September 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. first not 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	9 Months Ended
	Sep. 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. 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 98.1% 97.9% three September 30, 2018 2017, 98.2% 98.2% nine September 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 nine September 30, 2018 2017 September 30, 2018 December 31, 2017 Operating Revenue Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 88,750 $ 88,482 $ 287,330 $ 281,615 Changes in Accrued ARP Revenues (317 ) 471 (2,757 ) (1,192 ) Total Retail Sales Revenue 88,433 88,953 284,573 280,423 Wholesale Revenues – Company Generation 2,826 1,549 6,380 3,600 Other Revenues 14,183 12,897 41,179 40,163 Total Electric Segment Revenues $ 105,442 $ 103,399 $ 332,132 $ 324,186 Manufacturing Segment: Metal Parts and Tooling $ 55,864 $ 44,750 $ 170,179 $ 142,278 Plastic Products and Tooling 8,790 7,905 26,986 24,833 Other 2,373 1,700 6,678 4,965 Total Manufacturing Segment Revenues $ 67,027 $ 54,355 $ 203,843 $ 172,076 Plastics Segment – Sale of PVC Pipe Products $ 55,203 $ 58,708 $ 159,332 $ 146,416 Intersegment Eliminations $ (10 ) $ (5 ) $ (31 ) $ (18 ) Total $ 227,662 $ 216,457 $ 695,276 $ 642,660 Interest Charges Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,509 $ 6,362 $ 19,586 $ 19,187 Manufacturing 555 555 1,664 1,662 Plastics 150 157 460 483 Corporate and Intersegment Eliminations 335 319 887 1,050 Total $ 7,549 $ 7,393 $ 22,597 $ 22,382 Income Taxes Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 5,172 $ 3,548 $ 7,881 $ 12,052 Manufacturing 799 676 3,040 3,304 Plastics 2,276 3,826 6,897 8,074 Corporate (888 ) (1,015 ) (3,611 ) (4,135 ) Total $ 7,359 $ 7,035 $ 14,207 $ 19,295 Net Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 14,567 $ 10,869 $ 41,835 $ 36,563 Manufacturing 3,022 1,608 10,769 6,735 Plastics 6,432 6,092 19,505 13,166 Corporate (748 ) (796 ) (3,925 ) (2,445 ) Discontinued Operations -- (39 ) -- 78 Total $ 23,273 $ 17,734 $ 68,184 $ 54,097 Identifiable Assets September 30, December 31, (in thousands) 2018 2017 Electric $ 1,695,659 $ 1,690,224 Manufacturing 186,973 167,023 Plastics 100,981 87,230 Corporate 43,803 59,801 Total $ 2,027,416 $ 2,004,278

Note 3 - Rate and Regulatory Ma

Note 3 - Rate and Regulatory Matters	9 Months Ended
	Sep. 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. September 30, 2018 $103.6 100% Big Stone South–Brookings MVP 345 70 December 2011. third 2015 September 8, 2017. September 30, 2018 $72.4 100% Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, in base rates and through the TCR Rider in Minnesota, and through TCR Riders in North Dakota and South Dakota. 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 2016 10%. 2017 not March 30, 2018. $2.6 June 13, 2018, May 30, 2018, $2.9 October 1, 2018 ( first October 4, 2018 October 2018, November 1, 2018 $2.9 no $0.3 Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 second 2019. September 30, 2018 $2.5 Environmental Cost Recovery Rider 2010 2016 November 2017. Renewable Resource Adjustment November 1, 2017, one 2017 2018. August 29, 2018 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 In a September 26, 2018 $4.6 3.1% 9.77% 52.5% March 2018 $7.1 4.8% 10.3%. not September 28, 2018 January 1, 2019, March 2019 $2.3 September 30, 2018 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 26 26A 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 not Environmental Cost Recovery Rider not 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 A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 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 A – August 29, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 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 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075/kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 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: Three Months Ended September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives $ 1,488 $ 1,806 $ 4,300 $ 4,215 Renewable Resource Recovery 817 -- 2,001 -- Environmental Cost Recovery 24 1,669 (25 ) 7,305 Transmission Cost Recovery (1,196 ) (594 ) (1,683 ) 2,849 North Dakota Renewable Resource Adjustment 2,220 2,213 6,266 5,822 Environmental Cost Recovery 1,823 2,396 5,474 7,272 Transmission Cost Recovery 1,922 2,410 5,149 6,305 South Dakota Environmental Cost Recovery 545 613 1,580 1,755 Transmission Cost Recovery 496 596 1,282 1,324 Conservation Improvement Program Costs and Incentives 238 104 589 520 Total $ 8,377 $ 11,213 $ 24,933 $ 37,367 TCJA The TCJA reduced the federal corporate income tax rate from 35% 21%. 35% The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. August 9, 2018 No not The SDPUC required initial comments by February 1, 2018 December 31, 2017 As described above, OTP’s current general rate cases in North Dakota and South Dakota reflect the impact of the TCJA. OTP has accrued refund liabilities for revenues collected under rates set to recover higher levels of federal income taxes than OTP is currently incurring under the lower federal tax rates in the TCJA. As of September 30, 2018, $6.0 $0.8 January February 2018, $1.1 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 one MVPs—MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On November 12, 2013 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 September 30, 2018. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second second first On October 16, 2018 April 2017. 10.41%, 13.08% 206 60 30 OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 September 30, 2018 second

Note 4 - Regulatory Assets and

Note 4 - Regulatory Assets and Liabilities	9 Months Ended
	Sep. 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 September 30, 2018 Remaining Recovery/ Refund Period (in thousands) Current Long-Term Total (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 105,675 $ 114,765 see below Conservation Improvement Program Costs and Incentives 2 2,799 4,722 7,521 24 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,038 7,038 asset lives Deferred Marked-to-Market Losses 1 2,262 1,158 3,420 27 Unrecovered Tax Adjustment to Deferred Income Tax Asset 1 -- 2,739 2,739 see below Big Stone II Unrecovered Project Costs – Minnesota 1 673 1,123 1,796 31 Debt Reacquisition Premiums 1 218 805 1,023 168 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 695 695 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 475 -- 475 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 367 467 56 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 422 -- 422 7 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 333 -- 333 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 180 60 240 15 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1 -- 131 131 see below Deferred Income Taxes 1 -- 40 40 asset lives Total Regulatory Assets $ 16,552 $ 124,553 $ 141,105 Regulatory Liabilities: Deferred Income Taxes $ -- $ 148,103 $ 148,103 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,123 83,123 asset lives Refundable Fuel Clause Adjustment Revenues 6,632 -- 6,632 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 301 -- 301 6 South Dakota Environmental Cost Recovery Rider Accrued Refund 266 -- 266 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 221 -- 221 1 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 19 182 201 15 South Dakota Transmission Cost Recovery Rider Accrued Refund 181 -- 181 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 156 -- 156 15 North Dakota Environmental Cost Recovery Rider Accrued Refund 117 -- 117 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 107 107 see below Other 6 79 85 183 North Dakota Transmission Cost Recovery Rider Accrued Refund 27 -- 27 12 Total Regulatory Liabilities $ 7,926 $ 231,594 $ 239,520 Net Regulatory Asset/(Liability) Position $ 8,626 $ (107,041 ) $ (98,415 ) 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/ Refund Period (in thousands) Current Long-Term Total (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 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 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 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Other 5 84 89 192 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 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 715 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 September 30, 2018 December 2020. The Unrecovered Tax Adjustment to Deferred Income Tax Asset results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes , 740 980. 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 168 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. Minnesota Renewable Resource Rider Accrued Revenues relate to an increase in renewable revenue requirements resulting from the expiration of tax credits for certain wind turbines. The balance represents amounts subject to recovery from Minnesota customers that have not September 30, 2018. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. 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. 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. MISO Schedule 26/26A 26/26A The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not September 30, 2018. 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 asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC 740. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The North Dakota Renewable Resource 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 September 30, 2018. 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 September 30, 2018. 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 September 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 September 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 September 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 refundable to North Dakota customers as of September 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 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 September 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 were subject to refund as of December 31, 2017. 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 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	9 Months Ended
	Sep. 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 893 (986 ) (93 ) Common Stock Retirements (356 ) (2,656 ) (3,012 ) Net Income 68,184 68,184 Other Comprehensive Loss (176 ) (176 ) Employee Stock Incentive Plans Expense 3,402 3,402 Common Dividends ($1.005 per share) (39,895 ) (39,895 ) Balance, September 30, 2018 $ 198,324 343,210 $ 189,575 $ (5,807 ) $ 725,302 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 Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 September 30, 2018: Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 awards) 114,648 Executive Stock Performance Awards (2016 and 2017 awards) 18,600 Vesting of Restricted Stock Units 26,575 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (71,208 ) Common Shares Outstanding, September 30, 2018 39,664,884 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three nine September 30, 2018 2017. not Three Months ended September 30 Nine Months ended September 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,621,524 39,507,581 39,592,705 39,440,416 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 206,268 211,996 210,691 195,869 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 58,680 55,975 58,475 54,645 Nonvested Restricted Shares 14,761 16,982 17,712 18,923 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,332 2,832 2,522 3,009 Total Dilutive Shares 282,041 287,785 289,400 272,446 Weighted Average Common Shares Outstanding – Diluted 39,903,565 39,795,366 39,882,105 39,712,862 The effect of dilutive shares on earnings per share for the three nine September 30, 2018 2017, no $0.0125

Note 6 - Share-based Payments

Note 6 - Share-based Payments	9 Months Ended
	Sep. 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 nine September 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 Units Granted to Key Employee September 25, 2018 835 $ 43.25 100% 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, Compensation—Stock Compensation 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 September 30, 2018, $5.3 2.0 Amounts of compensation expense recognized under the Company’s five three nine September 30, 2018 2017 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 718 $ 494 $ 2,037 $ 1,568 Restricted Stock Units Granted to Executive Officers 174 104 596 472 Restricted Stock Granted to Executive Officers -- 16 16 54 Restricted Stock Granted to Nonemployee Directors 165 144 496 416 Restricted Stock Units Granted to Key Employees 92 87 257 255 Totals $ 1,149 $ 845 $ 3,402 $ 2,765

Note 7 - Retained Earnings and

Note 7 - Retained Earnings and Dividend Restriction	9 Months Ended
	Sep. 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 September 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 47.9% 58.5% 2018 October 18, 2018. September 30, 2018, 53.6% $469,000,000. $1,204,416,000.

Note 8 - Commitments and Contin

Note 8 - Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	8 . Commitments and Contingencies Construction and Other Purchase Commitments At September 30, 2018 2019 $26.2 December 31, 2017 2019 $41.0 September 30, 2018 December 31, 2021 $5.6 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 land easement payments and operating lease payments, primarily for 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 September 30, 2018 3 Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the 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 2015 111 CO2 not 2016. 2017, April 2018. On August 21, 2018 1 2 3 not October 31, 2018. three Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2018 not

Note 9 - Short-term and Long-te

Note 9 - Short-term and Long-term Borrowings	9 Months Ended
	Sep. 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 September 30, 2018 December 31, 2017: (in thousands) Line Limit In Use on September 30, 2018 Restricted due to Outstanding Letters of Credit Available on September 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 15,489 $ -- $ 114,511 $ 130,000 OTP Credit Agreement 170,000 -- 300 169,700 57,329 Total $ 300,000 $ 15,489 $ 300 $ 284,211 $ 187,329 On October 31, 2018 one October 31, 2022 October 31, 2023. 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 September 30, 2018 December 31, 2017: September 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ -- $ 15,489 $ 15,489 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 564 564 Total $ 512,000 $ 80,564 $ 592,564 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 169 169 Unamortized Long-Term Debt Issuance Costs 1,991 420 2,411 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,009 $ 79,975 $ 589,984 Total Short-Term and Long-Term Debt (with current maturities) $ 510,009 $ 95,633 $ 605,642 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	9 Months Ended
	Sep. 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 September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 4,845 $ 4,221 Interest Cost on Projected Benefit Obligation 3,363 3,534 10,089 10,604 Expected Return on Assets (5,300 ) (4,807 ) (15,899 ) (14,421 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 30 12 89 From Other Comprehensive Income 1 -- 1 -- 3 Amortization of Net Actuarial Loss: From Regulatory Asset 1,784 1,273 5,351 3,818 From Other Comprehensive Income 1 46 31 137 94 Net Periodic Pension Cost 2 $ 1,512 $ 1,469 $ 4,535 $ 4,408 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 455 $ 285 $ 1,162 $ 856 Service costs included in electric operation and maintenance expenses 1,119 1,100 3,561 3,300 Service costs included in other nonelectric expenses 41 33 121 101 Nonservice costs capitalized as regulatory assets (29 ) -- (74 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (74 ) 51 (235 ) 151 Cash flows no December 31, 2017 $20 first 2018. Executive Survivor and Supplemental Retirement Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 73 $ 300 $ 218 Interest Cost on Projected Benefit Obligation 399 421 1,197 1,264 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 12 12 From Other Comprehensive Income 1 10 10 29 29 Amortization of Net Actuarial Loss: From Regulatory Asset 66 70 200 213 From Other Comprehensive Income 1 166 110 496 330 Net Periodic Pension Cost 2 $ 745 $ 688 $ 2,234 $ 2,066 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 $ 24 $ 24 $ 74 $ 71 Service costs included in other nonelectric expenses 76 49 226 147 Nonservice costs included in n onservice cost components of postretirement benefits 645 615 1,934 1,848 Postretirement Benefits Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 382 $ 357 $ 1,145 $ 1,069 Interest Cost on Projected Benefit Obligation 646 678 1,937 2,034 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 1,236 699 From Other Comprehensive Income 1 11 5 32 17 Net Periodic Postretirement Benefit Cost 2 $ 1,451 $ 1,273 $ 4,350 $ 3,819 Effect of Medicare Part D Subsidy $ (37 ) $ (141 ) $ (110 ) $ (421 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 108 $ 247 $ 275 $ 742 Service costs included in electric operation and maintenance expenses 264 278 841 835 Service costs included in other nonelectric expenses 10 9 29 26 Nonservice costs capitalized as regulatory assets 301 -- 769 -- Nonservice costs included in n onservice cost components of postretirement benefits 768 739 2,436 2,216

Note 11 - Fair Value of Financi

Note 11 - Fair Value of Financial Instruments	9 Months Ended
	Sep. 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 September 30, 2018 December 31, 2017 1.50% LIBOR 1.25%, Long-Term Debt including Current Maturities 2 820. September 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 649 $ 649 $ 16,216 $ 16,216 Short-Term Debt (15,489 ) (15,489 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,153 ) (589,368 ) (490,566 ) (543,691 )

Note 13 - Income Tax Expense -

Note 13 - Income Tax Expense - Continuing Operations	9 Months Ended
	Sep. 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 September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 30,632 $ 24,808 $ 82,391 $ 73,314 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 7,964 $ 9,675 $ 21,422 $ 28,592 Increases (Decreases) in Tax from: Federal Production Tax Credits (707 ) (1,349 ) (2,757 ) (5,411 ) Property Related Differences and Other Regulatory Adjustments 1,187 103 (911 ) 243 North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (212 ) (774 ) (637 ) Excess Tax Deduction – Equity Method Stock Awards (73 ) -- (698 ) (697 ) Research and Development and Other Tax Credits (227 ) (189 ) (636 ) (576 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- Allowance for Funds Used During Construction – Equity (138 ) (92 ) (416 ) (250 ) Corporate-Owned Life Insurance (332 ) (118 ) (360 ) (620 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (298 ) (517 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (990 ) Other Items – Net 42 (281 ) 166 158 Income Tax Expense – Continuing Operations $ 7,359 $ 7,035 $ 14,207 $ 19,295 Effective Income Tax Rate – Continuing Operations 24.0 % 28.4 % 17.2 % 26.3 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Increases (Decreases) Related to Tax Positions for Prior Years 6 28 Increases Related to Tax Positions for Current Year 113 220 Uncertain Positions Resolved During Year (186 ) (206 ) Balance on September 30 $ 617 $ 933 The balance of unrecognized tax benefits as of September 30, 2018 September 30, 2018 not 12 no September 30, 2018. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2018, no 2015 2014 The Company recognized the income tax effects of the TCJA in its 2017 No. 118, 740, Income Taxes one December 31, 2017 September 30, 2018. not December 31, 2017 2018.

Significant Accounting Policies

Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 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 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 nine September 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 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 September 30, 2018 December 31, 2017: September 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,373 Corporate Debt Securities – Held by Captive Insurance Company $ 6,012 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 776 Total Assets $ 2,149 $ 7,539 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 September 30, 2018 $54.8 35%
Inventory, Policy [Policy Text Block]	Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2018 2017 Finished Goods $ 28,907 $ 26,605 Work in Process 19,124 14,222 Raw Material, Fuel and Supplies 46,584 47,207 Total Inventories $ 94,615 $ 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 nine 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) September 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 September 30, 2018 December 31, 2017: September 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,843 $ 12,648 15 - 203 Other 154 56 98 23 Total $ 22,645 $ 9,899 $ 12,746 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 Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 329 $ 336 $ 1,019 $ 1,001 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 September 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 12,059 $ 17,940
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. 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 nine September 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. first not 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 Significa_2

Note 1 - Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	September 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,373 Corporate Debt Securities – Held by Captive Insurance Company $ 6,012 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 776 Total Assets $ 2,149 $ 7,539 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]	September 30, December 31, (in thousands) 2018 2017 Finished Goods $ 28,907 $ 26,605 Work in Process 19,124 14,222 Raw Material, Fuel and Supplies 46,584 47,207 Total Inventories $ 94,615 $ 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) September 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]	September 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,843 $ 12,648 15 - 203 Other 154 56 98 23 Total $ 22,645 $ 9,899 $ 12,746 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 Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 329 $ 336 $ 1,019 $ 1,001
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 September 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 12,059 $ 17,940

Note 2 - Segment Information (T

Note 2 - Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Segment Reporting Information, by Segment [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 88,750 $ 88,482 $ 287,330 $ 281,615 Changes in Accrued ARP Revenues (317 ) 471 (2,757 ) (1,192 ) Total Retail Sales Revenue 88,433 88,953 284,573 280,423 Wholesale Revenues – Company Generation 2,826 1,549 6,380 3,600 Other Revenues 14,183 12,897 41,179 40,163 Total Electric Segment Revenues $ 105,442 $ 103,399 $ 332,132 $ 324,186 Manufacturing Segment: Metal Parts and Tooling $ 55,864 $ 44,750 $ 170,179 $ 142,278 Plastic Products and Tooling 8,790 7,905 26,986 24,833 Other 2,373 1,700 6,678 4,965 Total Manufacturing Segment Revenues $ 67,027 $ 54,355 $ 203,843 $ 172,076 Plastics Segment – Sale of PVC Pipe Products $ 55,203 $ 58,708 $ 159,332 $ 146,416 Intersegment Eliminations $ (10 ) $ (5 ) $ (31 ) $ (18 ) Total $ 227,662 $ 216,457 $ 695,276 $ 642,660 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,509 $ 6,362 $ 19,586 $ 19,187 Manufacturing 555 555 1,664 1,662 Plastics 150 157 460 483 Corporate and Intersegment Eliminations 335 319 887 1,050 Total $ 7,549 $ 7,393 $ 22,597 $ 22,382 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 5,172 $ 3,548 $ 7,881 $ 12,052 Manufacturing 799 676 3,040 3,304 Plastics 2,276 3,826 6,897 8,074 Corporate (888 ) (1,015 ) (3,611 ) (4,135 ) Total $ 7,359 $ 7,035 $ 14,207 $ 19,295 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2018 2017 2018 2017 Electric $ 14,567 $ 10,869 $ 41,835 $ 36,563 Manufacturing 3,022 1,608 10,769 6,735 Plastics 6,432 6,092 19,505 13,166 Corporate (748 ) (796 ) (3,925 ) (2,445 ) Discontinued Operations -- (39 ) -- 78 Total $ 23,273 $ 17,734 $ 68,184 $ 54,097 September 30, December 31, (in thousands) 2018 2017 Electric $ 1,695,659 $ 1,690,224 Manufacturing 186,973 167,023 Plastics 100,981 87,230 Corporate 43,803 59,801 Total $ 2,027,416 $ 2,004,278

Note 3 - Rate and Regulatory _2

Note 3 - Rate and Regulatory Matters (Tables)	9 Months Ended
	Sep. 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 A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 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 A – August 29, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 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 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075/kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 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 September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives $ 1,488 $ 1,806 $ 4,300 $ 4,215 Renewable Resource Recovery 817 -- 2,001 -- Environmental Cost Recovery 24 1,669 (25 ) 7,305 Transmission Cost Recovery (1,196 ) (594 ) (1,683 ) 2,849 North Dakota Renewable Resource Adjustment 2,220 2,213 6,266 5,822 Environmental Cost Recovery 1,823 2,396 5,474 7,272 Transmission Cost Recovery 1,922 2,410 5,149 6,305 South Dakota Environmental Cost Recovery 545 613 1,580 1,755 Transmission Cost Recovery 496 596 1,282 1,324 Conservation Improvement Program Costs and Incentives 238 104 589 520 Total $ 8,377 $ 11,213 $ 24,933 $ 37,367

Note 4 - Regulatory Assets an_2

Note 4 - Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Regulatory Assets and Liabilities [Table Text Block]	September 30, 2018 Remaining Recovery/ Refund Period (in thousands) Current Long-Term Total (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 105,675 $ 114,765 see below Conservation Improvement Program Costs and Incentives 2 2,799 4,722 7,521 24 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 7,038 7,038 asset lives Deferred Marked-to-Market Losses 1 2,262 1,158 3,420 27 Unrecovered Tax Adjustment to Deferred Income Tax Asset 1 -- 2,739 2,739 see below Big Stone II Unrecovered Project Costs – Minnesota 1 673 1,123 1,796 31 Debt Reacquisition Premiums 1 218 805 1,023 168 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 695 695 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 475 -- 475 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 367 467 56 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 422 -- 422 7 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 333 -- 333 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 180 60 240 15 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1 -- 131 131 see below Deferred Income Taxes 1 -- 40 40 asset lives Total Regulatory Assets $ 16,552 $ 124,553 $ 141,105 Regulatory Liabilities: Deferred Income Taxes $ -- $ 148,103 $ 148,103 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,123 83,123 asset lives Refundable Fuel Clause Adjustment Revenues 6,632 -- 6,632 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 301 -- 301 6 South Dakota Environmental Cost Recovery Rider Accrued Refund 266 -- 266 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 221 -- 221 1 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 19 182 201 15 South Dakota Transmission Cost Recovery Rider Accrued Refund 181 -- 181 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 156 -- 156 15 North Dakota Environmental Cost Recovery Rider Accrued Refund 117 -- 117 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 107 107 see below Other 6 79 85 183 North Dakota Transmission Cost Recovery Rider Accrued Refund 27 -- 27 12 Total Regulatory Liabilities $ 7,926 $ 231,594 $ 239,520 Net Regulatory Asset/(Liability) Position $ 8,626 $ (107,041 ) $ (98,415 ) December 31, 2017 Remaining Recovery/ Refund Period (in thousands) Current Long-Term Total (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 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 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 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Other 5 84 89 192 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 )

Note 5 - Reconciliation of Co_2

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)	9 Months Ended
	Sep. 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 893 (986 ) (93 ) Common Stock Retirements (356 ) (2,656 ) (3,012 ) Net Income 68,184 68,184 Other Comprehensive Loss (176 ) (176 ) Employee Stock Incentive Plans Expense 3,402 3,402 Common Dividends ($1.005 per share) (39,895 ) (39,895 ) Balance, September 30, 2018 $ 198,324 343,210 $ 189,575 $ (5,807 ) $ 725,302
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 awards) 114,648 Executive Stock Performance Awards (2016 and 2017 awards) 18,600 Vesting of Restricted Stock Units 26,575 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (71,208 ) Common Shares Outstanding, September 30, 2018 39,664,884
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Three Months ended September 30 Nine Months ended September 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,621,524 39,507,581 39,592,705 39,440,416 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 206,268 211,996 210,691 195,869 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 58,680 55,975 58,475 54,645 Nonvested Restricted Shares 14,761 16,982 17,712 18,923 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,332 2,832 2,522 3,009 Total Dilutive Shares 282,041 287,785 289,400 272,446 Weighted Average Common Shares Outstanding – Diluted 39,903,565 39,795,366 39,882,105 39,712,862

Note 6 - Share-based Payments (

Note 6 - Share-based Payments (Tables)	9 Months Ended
	Sep. 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 Units Granted to Key Employee September 25, 2018 835 $ 43.25 100% 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 September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 718 $ 494 $ 2,037 $ 1,568 Restricted Stock Units Granted to Executive Officers 174 104 596 472 Restricted Stock Granted to Executive Officers -- 16 16 54 Restricted Stock Granted to Nonemployee Directors 165 144 496 416 Restricted Stock Units Granted to Key Employees 92 87 257 255 Totals $ 1,149 $ 845 $ 3,402 $ 2,765

Note 9 - Short-term and Long-_2

Note 9 - Short-term and Long-term Borrowings (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Line of Credit Facilities [Table Text Block]	(in thousands) Line Limit In Use on September 30, 2018 Restricted due to Outstanding Letters of Credit Available on September 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 15,489 $ -- $ 114,511 $ 130,000 OTP Credit Agreement 170,000 -- 300 169,700 57,329 Total $ 300,000 $ 15,489 $ 300 $ 284,211 $ 187,329
Schedule of Debt [Table Text Block]	September 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ -- $ 15,489 $ 15,489 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 564 564 Total $ 512,000 $ 80,564 $ 592,564 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 169 169 Unamortized Long-Term Debt Issuance Costs 1,991 420 2,411 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,009 $ 79,975 $ 589,984 Total Short-Term and Long-Term Debt (with current maturities) $ 510,009 $ 95,633 $ 605,642 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 Ot_2

Note 10 - Pension Plan and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 4,845 $ 4,221 Interest Cost on Projected Benefit Obligation 3,363 3,534 10,089 10,604 Expected Return on Assets (5,300 ) (4,807 ) (15,899 ) (14,421 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 30 12 89 From Other Comprehensive Income 1 -- 1 -- 3 Amortization of Net Actuarial Loss: From Regulatory Asset 1,784 1,273 5,351 3,818 From Other Comprehensive Income 1 46 31 137 94 Net Periodic Pension Cost 2 $ 1,512 $ 1,469 $ 4,535 $ 4,408 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 455 $ 285 $ 1,162 $ 856 Service costs included in electric operation and maintenance expenses 1,119 1,100 3,561 3,300 Service costs included in other nonelectric expenses 41 33 121 101 Nonservice costs capitalized as regulatory assets (29 ) -- (74 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (74 ) 51 (235 ) 151 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 73 $ 300 $ 218 Interest Cost on Projected Benefit Obligation 399 421 1,197 1,264 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 12 12 From Other Comprehensive Income 1 10 10 29 29 Amortization of Net Actuarial Loss: From Regulatory Asset 66 70 200 213 From Other Comprehensive Income 1 166 110 496 330 Net Periodic Pension Cost 2 $ 745 $ 688 $ 2,234 $ 2,066 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 $ 24 $ 24 $ 74 $ 71 Service costs included in other nonelectric expenses 76 49 226 147 Nonservice costs included in n onservice cost components of postretirement benefits 645 615 1,934 1,848 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 382 $ 357 $ 1,145 $ 1,069 Interest Cost on Projected Benefit Obligation 646 678 1,937 2,034 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 1,236 699 From Other Comprehensive Income 1 11 5 32 17 Net Periodic Postretirement Benefit Cost 2 $ 1,451 $ 1,273 $ 4,350 $ 3,819 Effect of Medicare Part D Subsidy $ (37 ) $ (141 ) $ (110 ) $ (421 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 108 $ 247 $ 275 $ 742 Service costs included in electric operation and maintenance expenses 264 278 841 835 Service costs included in other nonelectric expenses 10 9 29 26 Nonservice costs capitalized as regulatory assets 301 -- 769 -- Nonservice costs included in n onservice cost components of postretirement benefits 768 739 2,436 2,216

Note 11 - Fair Value of Finan_2

Note 11 - Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Fair Value, by Balance Sheet Grouping [Table Text Block]	September 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 649 $ 649 $ 16,216 $ 16,216 Short-Term Debt (15,489 ) (15,489 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,153 ) (589,368 ) (490,566 ) (543,691 )

Note 13 - Income Tax Expense _2

Note 13 - Income Tax Expense - Continuing Operations (Tables)	9 Months Ended
	Sep. 30, 2018
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 30,632 $ 24,808 $ 82,391 $ 73,314 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 7,964 $ 9,675 $ 21,422 $ 28,592 Increases (Decreases) in Tax from: Federal Production Tax Credits (707 ) (1,349 ) (2,757 ) (5,411 ) Property Related Differences and Other Regulatory Adjustments 1,187 103 (911 ) 243 North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (212 ) (774 ) (637 ) Excess Tax Deduction – Equity Method Stock Awards (73 ) -- (698 ) (697 ) Research and Development and Other Tax Credits (227 ) (189 ) (636 ) (576 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- Allowance for Funds Used During Construction – Equity (138 ) (92 ) (416 ) (250 ) Corporate-Owned Life Insurance (332 ) (118 ) (360 ) (620 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (298 ) (517 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (990 ) Other Items – Net 42 (281 ) 166 158 Income Tax Expense – Continuing Operations $ 7,359 $ 7,035 $ 14,207 $ 19,295 Effective Income Tax Rate – Continuing Operations 24.0 % 28.4 % 17.2 % 26.3 %
Summary of Income Tax Contingencies [Table Text Block]	(in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Increases (Decreases) Related to Tax Positions for Prior Years 6 28 Increases Related to Tax Positions for Current Year 113 220 Uncertain Positions Resolved During Year (186 ) (206 ) Balance on September 30 $ 617 $ 933

Note 1 - Summary of Significa_3

Note 1 - Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2019USD ($)	Sep. 30, 2018USD ($)	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		$ 54,800
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 Significa_4

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	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 1 [Member]
Assets:
Total Assets	$ 2,149	$ 2,108
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Assets:
Investments	1,373	1,285
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets	776	823
Fair Value, Inputs, Level 2 [Member]
Assets:
Total Assets	7,539	7,160
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Assets:
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Assets:
Investments	6,012	5,373
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Assets:
Investments	1,527	1,787
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member]
Assets:
Other Assets

Note 1 - Summary of Significa_5

Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Finished Goods	$ 28,907	$ 26,605
Work in Process	19,124	14,222
Raw Material, Fuel and Supplies	46,584	47,207
Total Inventories	$ 94,615	$ 88,034

Note 1 - Summary of Significa_6

Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 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 Significa_7

Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Gross Carrying Amount	$ 22,645	$ 23,235
Accumulated Amortization	9,899	9,470
Net Carrying Amount	12,746	13,765
Customer Relationships [Member]
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	9,843	8,994
Net Carrying Amount	$ 12,648	$ 13,497
Customer Relationships [Member] | Minimum [Member]
Remaining Amortization Periods (Month)	1 year 90 days	2 years
Customer Relationships [Member] | Maximum [Member]
Remaining Amortization Periods (Month)	16 years 330 days	17 years 240 days
Other Intangible Assets [Member]
Gross Carrying Amount	$ 154	$ 154
Accumulated Amortization	56	17
Net Carrying Amount	$ 98	$ 137
Remaining Amortization Periods (Month)	1 year 330 days	2 years 240 days
Covenant Not to Compete [Member]
Gross Carrying Amount		$ 590
Accumulated Amortization		459
Net Carrying Amount		$ 131
Remaining Amortization Periods (Month)		240 days

Note 1 - Summary of Significa_8

Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Amortization Expense – Intangible Assets	$ 329	$ 336	$ 1,019	$ 1,001

Note 1 - Summary of Significa_9

Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands	Sep. 30, 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 Signific_10

Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Transactions Related to Capital Additions not Settled in Cash	$ 12,059	$ 17,940

Note 2 - Segment Information (D

Note 2 - Segment Information (Details Textual)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 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	98.10%	97.90%	98.20%	98.20%

Note 2 - Segment Information -

Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Total Operating Revenues	$ 227,662	$ 216,457	$ 695,276	$ 642,660
Interest charges	7,549	7,393	22,597	22,382
Income Taxes	7,359	7,035	14,207	19,295
Net Income (Loss)	23,273	17,734	68,184	54,097
Assets	2,027,416		2,027,416		$ 2,004,278
Discontinued Operations [Member]
Net Income (Loss)		(39)		78
Operating Segments [Member] | Electric [Member]
Revenue from Contracts with Customers	14,183	12,897	41,179	40,163
Regulated operating revenues	105,442	103,399	332,132	324,186
Interest charges	6,509	6,362	19,586	19,187
Income Taxes	5,172	3,548	7,881	12,052
Net Income (Loss)	14,567	10,869	41,835	36,563
Assets	1,695,659		1,695,659		1,690,224
Operating Segments [Member] | Electric [Member] | Retail [Member]
Revenue from Contracts with Customers	88,750	88,482	287,330	281,615
Changes in Accrued ARP Revenues	(317)	471	(2,757)	(1,192)
Regulated operating revenues	88,433	88,953	284,573	280,423
Operating Segments [Member] | Electric [Member] | Wholesale [Member]
Revenue from Contracts with Customers	2,826	1,549	6,380	3,600
Operating Segments [Member] | Manufacturing [Member]
Revenue from Contracts with Customers	67,027	54,355	203,843	172,076
Interest charges	555	555	1,664	1,662
Income Taxes	799	676	3,040	3,304
Net Income (Loss)	3,022	1,608	10,769	6,735
Assets	186,973		186,973		167,023
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member]
Revenue from Contracts with Customers	55,864	44,750	170,179	142,278
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member]
Revenue from Contracts with Customers	8,790	7,905	26,986	24,833
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member]
Revenue from Contracts with Customers	2,373	1,700	6,678	4,965
Operating Segments [Member] | Plastics [Member]
Revenue from Contracts with Customers	55,203	58,708	159,332	146,416
Interest charges	150	157	460	483
Income Taxes	2,276	3,826	6,897	8,074
Net Income (Loss)	6,432	6,092	19,505	13,166
Assets	100,981		100,981		87,230
Corporate and Eliminations [Member]
Interest charges	335	319	887	1,050
Income Taxes	(888)	(1,015)	(3,611)	(4,135)
Net Income (Loss)	(748)	(796)	(3,925)	(2,445)
Assets	43,803		43,803		$ 59,801
Intersegment Eliminations [Member]
Regulated operating revenues	$ (10)	$ (5)	$ (31)	$ (18)

Note 3 - Rate and Regulatory _3

Note 3 - Rate and Regulatory Matters (Details Textual)

Oct. 16, 2018

Sep. 26, 2018USD ($)

Jul. 06, 2018

Apr. 20, 2018USD ($)

Mar. 23, 2018USD ($)

Mar. 22, 2018USD ($)

Dec. 20, 2017USD ($)

Nov. 17, 2017USD ($)

Nov. 01, 2017

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 ($)

Sep. 30, 2018USD ($)

Dec. 31, 2018

Dec. 31, 2017USD ($)

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

$ 6,000,000

NORTH DAKOTA

Accrued Refund Liabilities Resulting from Tax Rate Reduction

800,000

South Dakota [Member]

Accrued Refund Liabilities Resulting from Tax Rate Reduction

1,100,000

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

10.41%

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] | Federal Energy Regulatory Commission [Member] | Maximum [Member]

Proposed Reduced Return on Equity Used in Transmission Rates

13.08%

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

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

2,500,000

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

$ 2,600,000

$ 2,600,000

Percentage Decrease in Energy Savings

10.00%

Amount Of Financial Incentive Requested

$ 2,900,000

Amount Of Financial Incentive Requested, At Risk of Subsequent Refund

300,000

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

Percentage of Allowed Rate of Return on Rate Base

7.97%

Percentage of Allowed Rate of Return on Equity

10.30%

10.30%

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), Amount

$ 4,600,000

$ 7,100,000

$ 13,100,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.10%

4.80%

General Rate Revenue Increase Requested, Decrease

$ 6,000,000

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

4,800,000

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

$ 1,200,000

Percentage of Requested Allowed Rate of Return on Equity

9.77%

Equity to Total Capitalization Ratio Basis for Return on Equity

52.50%

Contract with Customer, Refund Liability, Total

$ 2,300,000

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

$ 103,600,000

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

$ 72,400,000

Percentage of Assets of Project

100.00%

Note 3 - Rate and Regulatory _4

Note 3 - Rate and Regulatory Matters - Summary of Status of Updates for Previous Two Years for Various Rate Riders (Details) - Otter Tail Power Company [Member] $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)kWh
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member]
A - Approval Date	Oct. 4, 2018
Effective Date Requested or Approved	Nov. 1, 2018
Annual Revenue	$ 10,283
Rate rider rate (Kilowatt-Hour) | kWh	0.006
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member]
A - Approval Date	Sep. 15, 2017
Effective Date Requested or Approved	Oct. 1, 2017
Annual Revenue	$ 9,868
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2015 Incentive and Cost Recovery [Member]
A - Approval Date	Jul. 19, 2016
Effective Date Requested or Approved	Oct. 1, 2016
Annual Revenue	$ 8,590
Rate rider rate (Kilowatt-Hour) | kWh	0.00275
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date	Oct. 30, 2017	[1]
Effective Date Requested or Approved	Nov. 1, 2017	[1]
Annual Revenue	$ (3,311)	[1]
Rate	Various	[1]
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Jul. 5, 2016
Effective Date Requested or Approved	Sep. 1, 2016
Annual Revenue	$ 4,736
Rate	Various
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date	Mar. 9, 2016
Effective Date Requested or Approved	Apr. 1, 2016
Annual Revenue	$ 7,203
Rate	Various
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date	Oct. 30, 2017
Effective Date Requested or Approved	Nov. 1, 2017
Annual Revenue	$ (1,943)
Rate of base	(0.935%)
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Jul. 5, 2016
Effective Date Requested or Approved	Sep. 1, 2016
Annual Revenue	$ 11,884
Rate of base	6.927%
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member]
Effective Date Requested or Approved	Dec. 1, 2018
Annual Revenue
R - Request Date	Jul. 3, 2018
Rate of base	0.00%
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
A - Approval Date	Oct. 30, 2017
Effective Date Requested or Approved	Nov. 1, 2017
Annual Revenue	$ 1,279
Rate rider rate (Kilowatt-Hour) | kWh	0.00049
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member]
A - Approval Date	Aug. 29, 2018
Effective Date Requested or Approved	Nov. 1, 2018
Annual Revenue	$ 5,886
Rate rider rate (Kilowatt-Hour) | kWh	0.00244
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Dec. 14, 2016
Effective Date Requested or Approved	Jan. 1, 2017
Annual Revenue	$ 6,916
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date	Feb. 27, 2018
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,469
Rate	Various
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date	Nov. 29, 2017
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 7,959
Rate	Various
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date	Dec. 20, 2017
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 8,537
Rate of base	6.629%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Jun. 22, 2016
Effective Date Requested or Approved	Jul. 1, 2016
Annual Revenue	$ 10,359
Rate of base	7.904%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date	Feb. 27, 2018
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 7,718
Rate of base	5.593%
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date	Jul. 12, 2017
Effective Date Requested or Approved	Aug. 1, 2017
Annual Revenue	$ 9,917
Rate of base	7.633%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member]
A - Approval Date	Dec. 20, 2017
Effective Date Requested or Approved	Jan. 1, 2018
Annual Revenue	$ 9,989
Rate of base	7.756%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member]
A - Approval Date	Mar. 15, 2017
Effective Date Requested or Approved	Apr. 1, 2017
Annual Revenue	$ 9,156
Rate of base	7.005%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member]
A - Approval Date	Jun. 22, 2016
Effective Date Requested or Approved	Jul. 1, 2016
Annual Revenue	$ 9,262
Rate of base	7.573%
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member]
A - Approval Date	Feb. 27, 2018
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 9,650
Rate of base	7.493%
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Feb. 17, 2017
Effective Date Requested or Approved	Mar. 1, 2017
Annual Revenue	$ 2,053
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date	Feb. 12, 2016
Effective Date Requested or Approved	Mar. 1, 2016
Annual Revenue	$ 1,895
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date	Feb. 28, 2018
Effective Date Requested or Approved	Mar. 1, 2018
Annual Revenue	$ 1,779
Rate	Various
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
A - Approval Date	Oct. 18, 2018
Effective Date Requested or Approved	Oct. 18, 2018
Annual Revenue	$ 1,171
Rate	Various
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date	Oct. 26, 2016
Effective Date Requested or Approved	Nov. 1, 2016
Annual Revenue	$ 2,238
Rate rider rate (Kilowatt-Hour) | kWh	0.00536
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
A - Approval Date	Oct. 13, 2017
Effective Date Requested or Approved	Nov. 1, 2017
Annual Revenue	$ 2,082
Rate rider rate (Kilowatt-Hour) | kWh	0.00483
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member]
A - Approval Date	Oct. 18, 2018
Effective Date Requested or Approved	Oct. 18, 2018
Annual Revenue	$ (189)
Rate rider rate (Kilowatt-Hour) | kWh	(0.00075)
[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 _5

Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues recorded under rate riders	$ 8,377	$ 11,213	$ 24,933	$ 37,367
Conservation Improvement Program Costs and Incentives [Member] | Minnesota [Member]
Revenues recorded under rate riders	1,488	1,806	4,300	4,215
Conservation Improvement Program Costs and Incentives [Member] | South Dakota [Member]
Revenues recorded under rate riders	238	104	589	520
Renewable Resource Cost Recovery Rider [Member] | Minnesota [Member]
Revenues recorded under rate riders	817		2,001
Environmental Cost Recovery Rider [Member] | Minnesota [Member]
Revenues recorded under rate riders	24	1,669	(25)	7,305
Environmental Cost Recovery Rider [Member] | North Dakota [Member]
Revenues recorded under rate riders	1,823	2,396	5,474	7,272
Environmental Cost Recovery Rider [Member] | South Dakota [Member]
Revenues recorded under rate riders	545	613	1,580	1,755
Transmission Cost Recovery Rider [Member] | Minnesota [Member]
Revenues recorded under rate riders	(1,196)	(594)	(1,683)	2,849
Transmission Cost Recovery Rider [Member] | North Dakota [Member]
Revenues recorded under rate riders	1,922	2,410	5,149	6,305
Transmission Cost Recovery Rider [Member] | South Dakota [Member]
Revenues recorded under rate riders	496	596	1,282	1,324
Renewable Resource Adjustment [Member] | North Dakota [Member]
Revenues recorded under rate riders	$ 2,220	$ 2,213	$ 6,266	$ 5,822

Note 4 - Regulatory Assets an_3

Note 4 - Regulatory Assets and Liabilities (Details Textual)	9 Months Ended
	Sep. 30, 2018
Regulatory Noncurrent Asset, Remaining Recovery Period	14 years

Note 4 - Regulatory Assets an_4

Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		9 Months Ended	12 Months Ended
		Sep. 30, 2018	Dec. 31, 2017
Regulatory Assets - Current		$ 16,552	$ 22,551
Regulatory Assets - Long -Term		124,553	129,576
Regulatory Assets - Total		141,105	152,127
Regulatory Liabilities - Current		7,926	9,688
Regulatory Liabilities - Long -Term		231,594	232,893
Regulatory Liabilities - Total		239,520	242,581
Net Regulatory Asset Position - Current		8,626	12,863
Net Regulatory Asset Position - Long-Term		(107,041)	(103,317)
Net Regulatory Asset/(Liability) Position		(98,415)	(90,454)
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		148,103	149,052
Regulatory Liabilities - Total		$ 148,103	$ 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		83,123	83,100
Regulatory Liabilities - Total		$ 83,123	$ 83,100
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues [Member]
Regulatory Liabilities - Current		$ 6,632	$ 5,778
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 6,632	$ 5,778
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 266	$ 187
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 266	$ 187
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 221	$ 1,667
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 221	$ 1,667
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		30 days	330 days
North Dakota Renewable Resource Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 301
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 301
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		180 days
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current		$ 19	$ 132
Regulatory Liabilities - Long -Term		182	48
Regulatory Liabilities - Total		$ 201	$ 180
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 90 days	2 years
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 181	$ 151
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 181	$ 151
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
Minnesota Transmission Cost Recovery Rider Accrued Refund [member]
Regulatory Liabilities - Current		$ 156	$ 802
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 156	$ 802
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 90 days	300 days
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current			$ 208
Regulatory Liabilities - Long -Term		107
Regulatory Liabilities - Total		$ 107	$ 208
Regulatory Liabilities - Remaining Recovery/Refund Period		see below
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			120 days
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 5
Regulatory Liabilities - Long -Term		79	84
Regulatory Liabilities - Total		$ 85	$ 89
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		15 years 90 days	16 years
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 27	$ 349
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 27	$ 349
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 117
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 117
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
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
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current			$ 409
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total			$ 409
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year
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]	105,675	112,487
Regulatory Assets - Total	[1]	$ 114,765	$ 121,577
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 2,799	$ 7,385
Regulatory Assets - Long -Term	[2]	4,722	2,774
Regulatory Assets - Total	[2]	$ 7,521	$ 10,159
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	2 years	1 year 270 days
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	7,038	6,651
Regulatory Assets - Total	[1]	$ 7,038	$ 6,651
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 2,262	$ 4,063
Regulatory Assets - Long -Term	[1]	1,158	2,405
Regulatory Assets - Total	[1]	$ 3,420	$ 6,468
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 90 days	3 years
Deferred Income Tax Asset [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	2,739
Regulatory Assets - Total	[1]	$ 2,739
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 673	$ 650
Regulatory Assets - Long -Term	[1]	1,123	1,636
Regulatory Assets - Total	[1]	$ 1,796	$ 2,286
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	2 years 210 days	3 years 120 days
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 218	$ 254
Regulatory Assets - Long -Term	[1]	805	960
Regulatory Assets - Total	[1]	$ 1,023	$ 1,214
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	14 years	14 years 270 days
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[1]	$ 100	$ 100
Regulatory Assets - Long -Term	[1]	367	442
Regulatory Assets - Total	[1]	$ 467	$ 542
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	4 years 240 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]	695
Regulatory Assets - Total	[1]	$ 695
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member]
Regulatory Assets - Current	[1]	$ 422	$ 75
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 422	$ 75
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	210 days	1 year
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 475
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 475
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 333	$ 309
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 333	$ 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]	$ 180
Regulatory Assets - Long -Term	[1]	60	1,985
Regulatory Assets - Total	[1]	$ 240	$ 1,985
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year 90 days	2 years
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
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	131
Regulatory Assets - Total	[1]	$ 131
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below
Deferred Income Taxes [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	40
Regulatory Assets - Total	[1]	$ 40
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives
[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 Co_3

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	May 03, 2018
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations	$ 0.0125	$ 0.0125	$ 0.0125	$ 0.0125
Dividend Reinvestment and Share Purchase Plan [Member]
Shelf Registration, Shares					1,500,000

Note 5 - Reconciliation of Co_4

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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Balance, beginning			$ 696,892
Common Stock Issuances, Net of Expenses			(93)
Common Stock Retirements			(3,012)
Net Income	$ 23,273	$ 17,734	68,184	$ 54,097
Other Comprehensive Loss			(176)
Employee Stock Incentive Plans Expense			3,402
Common Dividends ($1.005 per share)			(39,895)
Balance, ending	725,302		725,302
Par Value, Common Shares [Member]
Balance, beginning			197,787
Common Stock Issuances, Net of Expenses			893
Common Stock Retirements			(356)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($1.005 per share)
Balance, ending	198,324		198,324
Premium on Common Shares [Member]
Balance, beginning			343,450
Common Stock Issuances, Net of Expenses			(986)
Common Stock Retirements			(2,656)
Net Income
Other Comprehensive Loss
Employee Stock Incentive Plans Expense			3,402
Common Dividends ($1.005 per share)
Balance, ending	343,210		343,210
Retained Earnings [Member]
Balance, beginning			161,286
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income			68,184
Other Comprehensive Loss
Employee Stock Incentive Plans Expense
Common Dividends ($1.005 per share)			(39,895)
Balance, ending	189,575		189,575
Accumulated Other Comprehensive Income/(Loss) [Member]
Balance, beginning			(5,631)
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Loss			(176)
Employee Stock Incentive Plans Expense
Common Dividends ($1.005 per share)
Balance, ending	$ (5,807)		$ (5,807)

Note 5 - Reconciliation of Co_5

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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Dividends Declared Per Common Share (in dollars per share)	$ 0.335	$ 0.32	$ 1.005	$ 0.96

Note 5 - Reconciliation of Co_6

Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	9 Months Ended
	Sep. 30, 2018shares
Common Shares Outstanding, beginning balance (in shares)	39,557,491
Vesting of Restricted Stock Units (in shares)	26,575
Restricted Stock Issued to Directors (in shares)	18,200
Directors Deferred Compensation (in shares)	578
Shares Withheld for Individual Income Tax Requirements (in shares)	(71,208)
Common Shares Outstanding, ending balance (in shares)	39,664,884
Perfromance Awards 2015 [Member]
Executive Stock Performance Awards (in shares)	114,648
Performance Awards 2016 and 2017 [Member]
Executive Stock Performance Awards (in shares)	18,600

Note 5 - Reconciliation of Co_7

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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Weighted Average Common Shares Outstanding – Basic (in shares)	39,621,524	39,507,581	39,592,705	39,440,416
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)	206,268	211,996	210,691	195,869
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	58,680	55,975	58,475	54,645
Nonvested Restricted Shares (in shares)	14,761	16,982	17,712	18,923
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,332	2,832	2,522	3,009
Total Dilutive Shares (in shares)	282,041	287,785	289,400	272,446
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,903,565	39,795,366	39,882,105	39,712,862

Note 6 - Share-based Payments_2

Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions	Feb. 05, 2018	Sep. 30, 2018
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Total		$ 5.3
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition		2 years
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]	9 Months Ended
	Sep. 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] | Key Employee [Member]
Shares/units granted, grant date	Sep. 25, 2018
Shares/units granted (in shares) | shares	835
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 43.25
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 Payments_3

Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals) - The 2014 Stock Incentive Plan [Member]	9 Months Ended
	Sep. 30, 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%
Key Employee [Member] | Restricted Stock [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 Payments_4

Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Stock compensation expense	$ 1,149	$ 845	$ 3,402	$ 2,765
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	718	494	2,037	1,568
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	174	104	596	472
Restricted Stock Units (RSUs) [Member] | Key Employees [Member]
Stock compensation expense	92	87	257	255
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense		16	16	54
Restricted Stock [Member] | Nonemployee Directors [Member]
Stock compensation expense	$ 165	$ 144	$ 496	$ 416

Note 7 - Retained Earnings an_2

Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($)	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Capitalization, Long-term Debt and Equity, Total	$ 1,315,286,000	$ 1,187,272,000
Otter Tail Power Company [Member]
Equity to Total Capitalization Ratio	53.60%
Net Assets Restricted from Distribution	$ 469,000,000
Capitalization, Long-term Debt and Equity, Total	$ 1,204,416,000
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] | Minnesota Public Utilities Commission [Member]
Public Utilities, Requested Equity Capital Structure, Percentage	58.50%

Note 8 - Commitments and Cont_2

Note 8 - Commitments and Contingencies (Details Textual) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
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] | 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	$ 26,200,000	$ 41,000,000
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2,040
Otter Tail Power Company [Member] | Coal Purchase Commitments 3 [Member]
Contract Expiration Year	2,020
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member]
Long-term Purchase Commitment, Amount	$ 5,600,000	$ 6,700,000

Note 9 - Short-term and Long-_3

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-_4

Note 9 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Line Limit	$ 300,000
In Use	15,489
Restricted due to Outstanding Letters of Credit	300
Available	284,211	$ 187,329
Otter Tail Corporation Credit Agreement [Member]
Line Limit	130,000
In Use	15,489
Restricted due to Outstanding Letters of Credit
Available	114,511	130,000
OTP Credit Agreement [Member]
Line Limit	170,000
In Use
Restricted due to Outstanding Letters of Credit	300
Available	$ 169,700	$ 57,329

Note 9 - Short-term and Long-_5

Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Short-Term Debt	$ 15,489	$ 112,371
Long-Term Debt	592,564	492,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	169	186
Unamortized Long-Term Debt Issuance Costs	2,411	2,145
Total Long-Term Debt net of Unamortized Debt Issuance Costs	589,984	490,380
Total Short-Term and Long-Term Debt (with current maturities)	605,642	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	564	684
Otter Tail Power Company [Member]
Short-Term Debt		112,371
Long-Term Debt	512,000	412,000
Less: Current Maturities net of Unamortized Debt Issuance Costs
Unamortized Long-Term Debt Issuance Costs	1,991	1,684
Total Long-Term Debt net of Unamortized Debt Issuance Costs	510,009	410,316
Total Short-Term and Long-Term Debt (with current maturities)	510,009	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	15,489
Long-Term Debt	80,564	80,711
Less: Current Maturities net of Unamortized Debt Issuance Costs	169	186
Unamortized Long-Term Debt Issuance Costs	420	461
Total Long-Term Debt net of Unamortized Debt Issuance Costs	79,975	80,064
Total Short-Term and Long-Term Debt (with current maturities)	95,633	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	$ 564	$ 684

Note 9 - Short-term and Long-_6

Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals)	9 Months Ended	12 Months Ended
	Sep. 30, 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 Ot_3

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 Ot_4

Note 10 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,615	$ 1,407	$ 4,845	$ 4,221
Interest Cost on Projected Benefit Obligation		3,363	3,534	10,089	10,604
Expected Return on Assets		(5,300)	(4,807)	(15,899)	(14,421)
From Regulatory Asset		4	30	12	89
From Other Comprehensive Income	[1]		1		3
From Regulatory Asset		1,784	1,273	5,351	3,818
From Other Comprehensive Income	[1]	46	31	137	94
Net Periodic Pension Cost	[2]	1,512	1,469	4,535	4,408
From Other Comprehensive Income	[1]	46	31	137	94
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		455	285	1,162	856
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		1,119	1,100	3,561	3,300
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		41	33	121	101
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		(29)		(74)
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		(74)	51	(235)	151
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		100	73	300	218
Interest Cost on Projected Benefit Obligation		399	421	1,197	1,264
From Regulatory Asset		4	4	12	12
From Other Comprehensive Income	[3]	10	10	29	29
From Regulatory Asset		66	70	200	213
From Other Comprehensive Income	[3]	166	110	496	330
Net Periodic Pension Cost	[4]	745	688	2,234	2,066
From Other Comprehensive Income	[3]	166	110	496	330
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		24	24	74	71
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		76	49	226	147
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		645	615	1,934	1,848
Other Postretirement Benefits Plan [Member]
Service Cost—Benefit Earned During the Period		382	357	1,145	1,069
Interest Cost on Projected Benefit Obligation		646	678	1,937	2,034
From Regulatory Asset		412	233	1,236	699
From Other Comprehensive Income	[1]	11	5	32	17
Net Periodic Pension Cost	[5]	1,451	1,273	4,350	3,819
Effect of Medicare Part D Subsidy		(37)	(141)	(110)	(421)
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member]
Net Periodic Pension Cost		108	247	275	742
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member]
Net Periodic Pension Cost		264	278	841	835
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member]
Net Periodic Pension Cost		10	9	29	26
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member]
Net Periodic Pension Cost		301		769
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member]
Net Periodic Pension Cost		$ 768	$ 739	$ 2,436	$ 2,216
[1]	Corporate cost included in nonservice cost components of postretirement benefits.
[2]	Allocation of Costs: Costs included in OTP capital expenditures $ 455 $ 285 $ 1,162 $ 856 Service costs included in electric operation and maintenance expenses 1,119 1,100 3,561 3,300 Service costs included in other nonelectric expenses 41 33 121 101 Nonservice costs capitalized as regulatory assets (29 ) -- (74 ) -- Nonservice costs included in nonservice cost components of postretirement benefits (74 ) 51 (235 ) 151
[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 $ 24 $ 24 $ 74 $ 71 Service costs included in other nonelectric expenses 76 49 226 147 Nonservice costs included in nonservice cost components of postretirement benefits 645 615 1,934 1,848
[5]	Costs included in OTP capital expenditures $ 108 $ 247 $ 275 $ 742 Service costs included in electric operation and maintenance expenses 264 278 841 835 Service costs included in other nonelectric expenses 10 9 29 26 Nonservice costs capitalized as regulatory assets 301 -- 769 -- Nonservice costs included in nonservice cost components of postretirement benefits 768 739 2,436 2,216

Note 11 - Fair Value of Finan_3

Note 11 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	9 Months Ended	12 Months Ended
	Sep. 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%	1.50%
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR

Note 11 - Fair Value of Finan_4

Note 11 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 649	$ 16,216
Short-Term Debt	(15,489)	(112,371)
Long-Term Debt including Current Maturities	(590,153)	(490,566)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	649	16,216
Short-Term Debt	(15,489)	(112,371)
Long-Term Debt including Current Maturities	$ (589,368)	$ (543,691)

Note 13 - Income Tax Expense _3

Note 13 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands	9 Months Ended
	Sep. 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 _4

Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Before Income Taxes – Continuing Operations	$ 30,632	$ 24,808	$ 82,391	$ 73,314
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017)	7,964	9,675	21,422	28,592
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(707)	(1,349)	(2,757)	(5,411)
Property Related Differences and Other Regulatory Adjustments	1,187	103	(911)	243
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(258)	(212)	(774)	(637)
Excess Tax Deduction – Equity Method Stock Awards	(73)		(698)	(697)
Research and Development and Other Tax Credits	(227)	(189)	(636)	(576)
Other Comprehensive Income Deferred Tax Rate Adjustment			(531)
Allowance for Funds Used During Construction – Equity	(138)	(92)	(416)	(250)
Corporate-Owned Life Insurance	(332)	(118)	(360)	(620)
Employee Stock Ownership Plan Dividend Deduction	(99)	(172)	(298)	(517)
Section 199 Domestic Production Activities Deduction		(330)		(990)
Other Items – Net	42	(281)	166	158
Income Tax Expense – Continuing Operations	$ 7,359	$ 7,035	$ 14,207	$ 19,295
Effective Income Tax Rate – Continuing Operations	24.00%	28.40%	17.20%	26.30%

Note 13 - Income Tax Expense _5

Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Composite Federal and State Statutory Rate	26.00%	39.00%	26.00%	39.00%

Note 13 - Income Tax Expense _6

Note 13 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Balance, beginning	$ 684	$ 891
Increases (Decreases) Related to Tax Positions for Prior Years	6	28
Increases Related to Tax Positions for Current Year	113	220
Uncertain Positions Resolved During Year	(186)	(206)
Balance, ending	$ 617	$ 933