10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[ X]    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

OR

[ ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number            0-53713

OTTER TAIL CORPORATION

(Exact name of registrant as specified in its charter)

Minnesota	27-0383995
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

215 South Cascade Street, Box 496, Fergus Falls, Minnesota	56538-0496
(Address of principal executive offices)	(Zip Code)

866-410-8780

(Registrant's telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  ☑     No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑       No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.:

Large accelerated filer ☑	Accelerated filer ☐
Non-accelerated filer ☐	Smaller reporting company ☐	Emerging growth company ☐
(Do not check if a smaller reporting company)

If an emerging growth company, indicate by checkmark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).

Yes ☐    No ☑

Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date:

October 31, 2017 – 39,557,491 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

Part I. Financial Information		Page No.
Item 1.	Financial Statements
	Consolidated Balance Sheets – September 30, 2017 and December 31, 2016 (not audited)	2 & 3
	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2017 and 2016 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2017 and 2016 (not audited)	5
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2017 and 2016 (not audited)	6
	Condensed Notes to Consolidated Financial Statements (not audited)	7-30
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31-48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	49
Part II. Other Information
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	49
Signatures		50

1

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	September 30, 2017		December 31, 2016
Assets
Current Assets
Cash and Cash Equivalents	$	826	$	--
Accounts Receivable:
Trade—Net		87,510		68,242
Other		7,704		5,850
Inventories		78,915		83,740
Unbilled Revenues		14,948		20,080
Income Taxes Receivable		--		662
Regulatory Assets		21,582		21,297
Other		16,715		8,144
Total Current Assets		228,200		208,015
Investments		8,599		8,417
Other Assets		34,992		34,104
Goodwill		37,572		37,572
Other Intangibles—Net		14,097		14,958
Regulatory Assets		122,670		132,094
Plant
Electric Plant in Service		1,953,375		1,860,357
Nonelectric Operations		214,159		211,826
Construction Work in Progress		138,900		153,261
Total Gross Plant		2,306,434		2,225,444
Less Accumulated Depreciation and Amortization		785,667		748,219
Net Plant		1,520,767		1,477,225
Total Assets	$	1,966,897	$	1,912,385

See accompanying condensed notes to consolidated financial statements.

2

Otter Tail Corporation

Consolidated Balance Sheets 

(not audited)

(in thousands, except share data)	September 30, 2017			December 31, 2016
Liabilities and Equity
Current Liabilities
Short-Term Debt	$	103,637		$	42,883
Current Maturities of Long-Term Debt		197			33,201
Accounts Payable		96,217			89,350
Accrued Salaries and Wages		17,596			17,497
Accrued Taxes		13,277			16,000
Other Accrued Liabilities		14,400			15,377
Liabilities of Discontinued Operations		852			1,363
Total Current Liabilities		246,176			215,671
Pensions Benefit Liability		98,632			97,627
Other Postretirement Benefits Liability		63,215			62,571
Other Noncurrent Liabilities		22,921			21,706
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		242,568			226,591
Deferred Tax Credits		21,747			22,849
Regulatory Liabilities		84,281			82,433
Other		4,432			7,492
Total Deferred Credits		353,028			339,365
Capitalization
Long-Term Debt—Net		490,406			505,341
Cumulative Preferred Shares– Authorized 1,500,000 Shares Without Par Value; Outstanding – None		--			--
Cumulative Preference Shares – Authorized 1,000,000 Shares Without Par Value; Outstanding – None		--			--
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2017—39,557,491 Shares; 2016—39,348,136 Shares		197,787			196,741
Premium on Common Shares		342,573			337,684
Retained Earnings		155,618			139,479
Accumulated Other Comprehensive Loss		(3,459	)		(3,800	)
Total Common Equity		692,519			670,104
Total Capitalization		1,182,925			1,175,445
Total Liabilities and Equity	$	1,966,897		$	1,912,385

See accompanying condensed notes to consolidated financial statements. 

3

 Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except share and per-share amounts)	2017			2016		2017		2016
Operating Revenues
Electric	$	103,394		$	102,712	$	324,168	$	313,615
Product Sales		113,063			94,463		318,492		293,284
Total Operating Revenues		216,457			197,175		642,660		606,899
Operating Expenses
Production Fuel – Electric		16,096			14,789		44,955		40,479
Purchased Power – Electric System Use		13,371			11,473		48,935		43,486
Electric Operation and Maintenance Expenses		36,570			36,207		112,799		115,206
Cost of Products Sold (depreciation included below)		86,230			75,405		245,520		228,993
Other Nonelectric Expenses		10,933			10,197		31,535		30,890
Depreciation and Amortization		17,927			18,314		53,689		55,128
Property Taxes – Electric		3,721			3,506		11,228		10,774
Total Operating Expenses		184,848			169,891		548,661		524,956
Operating Income		31,609			27,284		93,999		81,943
Interest Charges		7,393			8,026		22,382		23,996
Other Income		592			499		1,697		2,431
Income Before Income Taxes—Continuing Operations		24,808			19,757		73,314		60,378
Income Tax Expense—Continuing Operations		7,035			5,163		19,295		15,738
Net Income from Continuing Operations		17,773			14,594		54,019		44,640
Discontinued Operations
(Loss) Income – net of Income Tax (Benefit) Expense of  ($25), $14, $53 and $114 for the respective periods		(39	)		22		78		171
Net Income		17,734			14,616		54,097		44,811
Average Number of Common Shares Outstanding—Basic		39,507,581			38,832,659		39,440,416		38,316,324
Average Number of Common Shares Outstanding—Diluted		39,795,366			39,005,706		39,712,862		38,457,401
Basic Earnings Per Common Share:
Continuing Operations	$	0.45		$	0.38	$	1.37	$	1.17
Discontinued Operations		--			--		--		--
	$	0.45		$	0.38	$	1.37	$	1.17
Diluted Earnings Per Common Share:
Continuing Operations	$	0.45		$	0.37	$	1.36	$	1.16
Discontinued Operations		--			--		--		0.01
	$	0.45		$	0.37	$	1.36	$	1.17
Dividends Declared Per Common Share	$	0.3200		$	0.3125	$	0.9600	$	0.9375

See accompanying condensed notes to consolidated financial statements. 

4

Otter Tail Corporation

Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			2016
Net Income	$	17,734		$	14,616		$	54,097		$	44,811
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period		(1	)		(3	)		(2	)		(3	)
Gains (Losses) Arising During Period		52			(35	)		90			65
Income Tax (Expense) Benefit		(18	)		13			(31	)		(22	)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		33			(25	)		57			40
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		157			161			473			470
Income Tax Expense		(63	)		(64	)		(189	)		(188	)
Pension and Postretirement Benefit Plans – net-of-tax		94			97			284			282
Total Other Comprehensive Income		127			72			341			322
Total Comprehensive Income	$	17,861		$	14,688		$	54,438		$	45,133

See accompanying condensed notes to consolidated financial statements. 

5

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Nine Months Ended September 30,
(in thousands)	2017			2016
Cash Flows from Operating Activities
Net Income	$	54,097		$	44,811
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		(78	)		(171	)
Depreciation and Amortization		53,689			55,128
Deferred Tax Credits		(1,102	)		(1,242	)
Deferred Income Taxes		15,680			14,924
Change in Deferred Debits and Other Assets		7,875			5,595
Discretionary Contribution to Pension Plan		--			(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		1,788			5,999
Allowance for Equity/Other Funds Used During Construction		(636	)		(605	)
Stock Compensation Expense—Equity Awards		2,765			1,151
Other—Net		99			(73	)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(21,122	)		(3,490	)
Change in Inventories		4,825			4,766
Change in Other Current Assets		3,079			1,690
Change in Payables and Other Current Liabilities		(5,153	)		(5,945	)
Change in Interest and Income Taxes Receivable/Payable		(1,595	)		2,538
Net Cash Provided by Continuing Operations		114,211			115,076
Net Cash Used in Discontinued Operations		(134	)		(333	)
Net Cash Provided by Operating Activities		114,077			114,743
Cash Flows from Investing Activities
Capital Expenditures		(94,549	)		(125,913	)
Net Proceeds from Disposal of Noncurrent Assets		2,456			4,167
Final Purchase Price Adjustment – BTD-Georgia Acquisition		--			1,500
Cash Used for Investments and Other Assets		(3,158	)		(3,161	)
Net Cash Used in Investing Activities		(95,251	)		(123,407	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		4,826			(841	)
Net Short-Term Borrowings (Repayments)		60,754			(43,499	)
Proceeds from Issuance of Common Stock – net of Issuance Expenses		4,349			39,378
Payments for Retirement of Capital Stock		(1,799	)		(104	)
Proceeds from Issuance of Long-Term Debt		--			50,000
Short-Term and Long-Term Debt Issuance Expenses		--			(157	)
Payments for Retirement of Long-Term Debt		(48,172	)		(161	)
Dividends Paid		(37,958	)		(35,952	)
Net Cash (Used in) Provided by Financing Activities		(18,000	)		8,664
Net Change in Cash and Cash Equivalents		826			--
Cash and Cash Equivalents at Beginning of Period		--			--
Cash and Cash Equivalents at End of Period	$	826		$	--

See accompanying condensed notes to consolidated financial statements.

6

OTTER TAIL CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)

In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016. Because of seasonal and other factors, the earnings for the three- and nine-month periods ended September 30, 2017 should not be taken as an indication of earnings for all or any part of the balance of the year.

The following condensed notes are numbered to correspond to numbers of the notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016.

1. Summary of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

Fair Value Measurements

The Company follows Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.

7

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, 2017 and December 31, 2016:

September 30, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds– Held by Captive Insurance Company	$	1,275
Corporate Debt Securities – Held by Captive Insurance Company			$	5,039
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				2,099
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		714
Total Assets	$	1,989	$	7,138

December 31, 2016 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,280
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company				2,945
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	849
Total Assets	$	849	$	8,225

The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:

Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.

Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012 the Coyote Station owners, including Otter Tail Power Company (OTP), entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of September 30, 2017 could be as high as $58.0 million, OTP’s 35% share of unrecovered costs.

8

Inventories

Inventories, valued at the lower of cost or net realizable value, consist of the following:

	September 30,		December 31,
(in thousands)	2017		2016
Finished Goods	$	19,500	$	27,755
Work in Process		13,885		11,754
Raw Material, Fuel and Supplies		45,530		44,231
Total Inventories	$	78,915	$	83,740

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2016 indicated the fair values are substantially in excess of their respective book values and not impaired.

The following table indicates there were no changes to goodwill by business segment during the first nine months of 2017:

(in thousands)	Gross Balance December 31, 2016		Accumulated Impairments		Balance (net of impairments) December 31, 2016		Adjustments to Goodwill in 2017		Balance (net of impairments) September 30, 2017
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, 2017 and December 31, 2016:

September 30, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,710	$	13,781	27	-	215
Covenant not to Compete		590		410		180		11
Other		140		4		136		35
Total	$	23,221	$	9,124	$	14,097
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36	-	224
Covenant not to Compete		590		262		328		20
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2017		2016		2017		2016
Amortization Expense – Intangible Assets	$	336	$	348	$	1,001	$	1,103

The estimated annual amortization expense for these intangible assets for the next five years is:

(in thousands)	2017		2018		2019		2020		2021
Estimated Amortization Expense – Intangible Assets	$	1,346	$	1,313	$	1,181	$	1,131	$	1,099

9

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	2017		2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	17,940	$	11,552

New Accounting Standards Adopted

Accounting Standards Update (ASU) 2015-11—In July 2015 the Financial Accounting Standards Board (FASB) issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update was effective prospectively for fiscal years and interim periods beginning after December 15, 2016. The Company adopted the updates in ASU 2015-11 in the first quarter of 2017. The adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements as market and net realizable value were substantially the same for the inventories of its manufacturing companies.

New Accounting Standards Pending Adoption

ASU 2014-09—In May 2014 the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. The Company does not plan to adopt the updated guidance prior to January 1, 2018. As of September 30, 2017 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is developing controls for new processes that will be required to track and report revenues where the timing of revenue recognition will change under ASU 2014-09. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09. The Company will adopt the updates in ASU 2014-09 on a modified retrospective basis with the cumulative effect of initial application on retained earnings and other balance sheet accounts, if any, recognized on January 1, 2018, the date of initial application. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard.

ASU 2016-02—In February 2016 the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, has developed a list of all current leases outstanding and is identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and is evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.

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ASU 2017-04—In January 2017 the FASB issued ASU No. 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04), whichsimplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill.In computing the implied fair value of goodwill under Step 2, an entity had to perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination.Under the amendments in ASU 2017-04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019.Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.

ASU 2017-07—In March 2017 the FASB issued ASU No. 2017-07, Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07), which is intended to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. ASC Topic 715, Compensation—Retirement Benefits (ASC 715), does not prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does not require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets.The amendments in ASU 2017-07 require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost as defined in ASC 715 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in ASU 2017-07 also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU 2017-07 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets.

The majority of the Company’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU 2017-07 may have on its consolidated financial statements, financial position and results of operations and is determining the adjustments and regulatory assets to be established in order to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under the ASU 2017-07 amendments to GAAP. The non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on the Company’s consolidated income statements upon adoption of the amendments in ASU 2017-07.

The Company’s non-service costs components of net periodic post-retirement benefit costs that will be capitalized to plant in service in 2017 but that would be recorded as regulatory assets if the amendments in ASU 2017-07 were applicable in 2017 are expected to be $0.7 million. The Company’s non-service costs components of net periodic post-retirement benefit costs included in operating expense in 2017 that would be included in other income and deductions under ASU 2017-07 are expected to be $5.7 million. The Company does not plan to adopt the updates in ASU 2017-07 prior to the first quarter of 2018, the required effective period for application of the updates by the Company.

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2. Segment Information

Segment Information

The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. These businesses sell products and provide services to customers primarily in the United States. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

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 polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

No single customer accounted for over 10% of the Company’s consolidated revenues in 2016. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 97.9% and 98.5% of its operating revenues for the respective three-month periods ended September 30, 2017 and 2016, and 98.2% and 98.6% of its operating revenues for the respective nine-month periods ended September 30, 2017 and 2016.

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- and nine-month periods ended September 30, 2017 and 2016 and total assets by business segment as of September 30, 2017 and December 31, 2016 are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2017			2016			2017			2016
Electric	$	103,399		$	102,723		$	324,186		$	313,642
Manufacturing		54,355			52,171			172,076			170,443
Plastics		58,708			42,292			146,416			122,841
Intersegment Eliminations		(5	)		(11	)		(18	)		(27	)
Total	$	216,457		$	197,175		$	642,660		$	606,899

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Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	2017		2016		2017		2016
Electric	$	6,362	$	6,304	$	19,187	$	18,744
Manufacturing		555		974		1,662		2,972
Plastics		157		273		483		796
Corporate and Intersegment Eliminations		319		475		1,050		1,484
Total	$	7,393	$	8,026	$	22,382	$	23,996

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2017			2016			2017			2016
Electric	$	3,548		$	4,730		$	12,052		$	11,262
Manufacturing		676			182			3,304			2,992
Plastics		3,826			1,577			8,074			5,206
Corporate		(1,015	)		(1,326	)		(4,135	)		(3,722	)
Total	$	7,035		$	5,163		$	19,295		$	15,738

Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2017			2016			2017			2016
Electric	$	10,869		$	12,513		$	36,563		$	34,199
Manufacturing		1,608			1,246			6,735			6,108
Plastics		6,092			2,346			13,166			7,983
Corporate		(796	)		(1,511	)		(2,445	)		(3,650	)
Discontinued Operations		(39	)		22			78			171
Total	$	17,734		$	14,616		$	54,097		$	44,811

Identifiable Assets

	September 30,		December 31,
(in thousands)	2017		2016
Electric	$	1,660,591	$	1,622,231
Manufacturing		167,004		166,525
Plastics		98,283		84,592
Corporate		41,019		39,037
Total	$	1,966,897	$	1,912,385

3. Rate and Regulatory Matters

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 Federal Energy Regulatory Commission (FERC) impacting OTP’s revenues in 2017 and 2016.

Major Capital Expenditure Projects

Big Stone South–Brookings Multi-Value Transmission Project (MVP) and Capacity Expansion 2020 (CapX2020) Project—This 345 kiloVolt (kV) transmission line extends approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011.

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MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the third quarter of 2015 and the line was energized on September 8, 2017.OTP’s capitalized costs on this project as of September 30, 2017 were approximately $70.0 million, which includes assets that are 100% owned by OTP.

Big Stone South–Ellendale MVP—This is a 345 kV transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized costs on this project as of September 30, 2017 were approximately $78.4 million, which includes assets that are 100% owned by OTP.

Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

Minnesota

2016 General Rate Case—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base will decrease from 8.61% to 7.5056% and its allowed rate of return on equity will decrease from 10.74% to 9.41%. On July 6, 2017 the MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case and confirmed details of its May 1, 2017 order approving OTP’s request for a revenue increase in Minnesota.

The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South-Brookings and Big Stone South-Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (ECR) and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

Information on interim and final rate increases and interim revenue refund accrued is detailed in the tables below:

($ in thousands)	Interim Rates Authorized April 14, 2016			Final Rates
Revenue Increase – Annualized based on Test Year Data	$	16,816		$	12,100
Revenue Percent Increase		9.56	%		6.23	%
Return on Rate Base		8.07	%		7.5056	%
Jurisdictional Rate Basebased on Test Year Data	$	483,000		$	471,000
Return on Equity		10.1	%		9.41	%
Based on Equity to Total Capital of		52.50	%		52.50	%
Debt to Total Capital		47.50	%		47.50	%

Interim Revenue (in thousands)	April 16, 2016 through September 30, 2017
Billed		$	21,847
Accrued Refund		$	8,237
Net Interim Revenue		$	13,610
Interest on Refundable Amount		$	233
Refund Liability as of September 30, 2017		$	8,470

In addition to the interim rate refund, OTP will be required to refund the difference between (1) amounts collected under its MinnesotaECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. As of September 30, 2017 the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts will be refunded to Minnesota customers over a 12-month period through reductions in the Minnesota ECR and TCR rider rates that take effect November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

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OTP will continue to accrue the interim and rider rate refunds until final rates become effective, for bills rendered on and after November 1, 2017.The interim rate refund, including interest, will be applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017.

Minnesota Conservation Improvement Programs (MNCIP)—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On May 25, 2016 the MPUC adopted the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The new model provides utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. MNCIP incentives include $5.0 million approved for 2016, $4.3 million approved for 2015 and $3.0 million approved for 2014.

Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.

In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the Commission’s Order diverts interstate wholesale revenues that have been approved by FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appealsto contest the portion of the order requiring OTP to allocate costs between jurisdictions of the FERC MVP transmission projects in the TCR rider. OTP believes the MPUC-ordered treatment conflicts with federal authority over transmission of electricity in interstate commerce and rates for the transmission of electricity subject to the jurisdiction of the FERC as set forth in the Federal Power Act of 1935, as amended (Federal Power Act).

Environmental Cost Recovery Rider—OTP has an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provides for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In OTP’s 2016 general rate case, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, with the transition occurring when final rates are implemented.

North Dakota

General Rates—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an increase in annual revenues from non-fuel base rates of $13.1 million or 8.7%. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of return on equity of 10.30%. Pursuant to the request, an interim rate increase is expected to go into effect on January 1, 2018.

OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.

Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.

Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case.

Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCSand Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects. The ECR rider provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case.

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South Dakota

2010 General Rate Case—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.

Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities.

Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

Rate Rider Updates

The following table provides summary information on the status of updates since January 1, 2015 for the rate riders described above:

Rate Rider	R - Request Date A - Approval Date	Effective Date Requested or Approved	Annual Revenue ($000s)			Rate
Minnesota
Conservation Improvement Program
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
2014 Incentive and Cost Recovery	A – July 10, 2015	October 1, 2015	$	8,689		$0.00287/kwh
Transmission Cost Recovery
2017 Rate Reset1	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
2014 Annual Update	A – February 18, 2015	March 1, 2015	$	8,388		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	-0.935% of Rev
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of Rev
2015 Annual Update	A – March 9, 2016	October 1, 2015	$	12,104		7.006% of Rev
North Dakota
Renewable Resource Adjustment
2016 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.005% of Rev
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7.573% of Rev
2014 Annual Update	A – March 25, 2015	April 1, 2015	$	5,441		4.069% of Rev
Transmission Cost Recovery
2017 Annual Update	R – August 31, 2017	January 1, 2018	$	8,593		Various
2016 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
2015 Annual Update	A – December 16, 2015	January 1, 2016	$	9,985		Various
Environmental Cost Recovery
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
2015 Annual Update	A – June 17, 2015	July 1, 2015	$	12,249		9.193% of base
South Dakota
Transmission Cost Recovery
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
2014 Annual Update	A – February 13, 2015	March 1, 2015	$	1,538		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00483/kwh
2016 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh
2015 Annual Update	A – October 15, 2015	November 1, 2015	$	2,728		$0.00643/kwh

¹Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

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The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota:

Revenues Recorded under Rider Rates	Three Months Ended September 30,					Nine Months Ended September 30,
Rate Rider (in thousands)	2017			2016		2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives1	$	2,499		$	2,839	$	6,567	$	7,554
Transmission Cost Recovery		(594	)		779		2,849		4,188
Environmental Cost Recovery		1,669			3,127		7,305		9,362
North Dakota
Renewable Resource Adjustment		2,213			2,170		5,822		6,151
Transmission Cost Recovery		2,410			1,950		6,305		6,155
Environmental Cost Recovery		2,396			2,762		7,272		8,344
South Dakota
Transmission Cost Recovery		596			335		1,324		1,397
Environmental Cost Recovery		613			691		1,755		1,951
Conservation Improvement Program Costs and Incentives		104			135		520		418

¹Includes MNCIP costs recovered in base rates.

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.

Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called 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 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. A number of parties requested rehearing of the September 2016 order and the requests are pending FERC action.

On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.

On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. OTP is currently waiting for the issuance of a FERC order on the second complaint.

Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of September 30, 2017.

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In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required.On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETO complaint. If FERC grants the motion to dismiss, it would eliminate the refund obligation from the second complaint and the ROE from the first complaint would remain in effect.

4. Regulatory Assets and Liabilities

As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations (ASC 980). This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	September 30, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,444	$	103,434	$	109,878	see below
Conservation Improvement Program Costs and Incentives2		8,230		2,351		10,581		24
Deferred Marked-to-Market Losses1		4,063		3,420		7,483		39
Accumulated ARO Accretion/Depreciation Adjustment1		--		6,525		6,525	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		88		2,432		2,520		27
Big Stone II Unrecovered Project Costs – Minnesota1		658		1,597		2,255		43
Debt Reacquisition Premiums1		252		1,026		1,278		180
Recoverable Fuel and Purchased Power Costs1		885		--		885		12
Deferred Income Taxes1		--		833		833	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		189		585		774		18
Big Stone II Unrecovered Project Costs – South Dakota2		100		467		567		68
Minnesota Deferred Rate Case Expenses Subject to Recovery1		496		--		496		7
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		142		--		142		3
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		35		--		35		3
Total Regulatory Assets	$	21,582	$	122,670	$	144,252
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	82,485	$	82,485	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		1,808		616		2,424		24
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,722		--		1,722		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		716		342		1,058		15
Deferred Income Taxes		--		720		720	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		385		--		385		7
South Dakota Environmental Cost Recovery Rider Accrued Refund		252		--		252		12
South Dakota Transmission Cost Recovery Rider Accrued Refund		172		--		172		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		99		33		132		15
Other		6		85		91		195
North Dakota Environmental Cost Recovery Rider Accrued Refund		43		--		43		12
Total Regulatory Liabilities	$	5,203	$	84,281	$	89,484
Net Regulatory Asset Position	$	16,379	$	38,389	$	54,768

¹Costs subject to recovery without a rate of return.

²Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

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	December 31, 2016						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,443	$	108,267	$	114,710	see below
Conservation Improvement Program Costs and Incentives2		4,836		5,158		9,994		21
Deferred Marked-to-Market Losses1		4,063		6,467		10,530		48
Accumulated ARO Accretion/Depreciation Adjustment1		--		6,153		6,153	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		333		--		333		12
Big Stone II Unrecovered Project Costs – Minnesota1		778		2,087		2,865		52
Debt Reacquisition Premiums1		325		1,214		1,539		189
Recoverable Fuel and Purchased Power Costs1		1,798		--		1,798		12
Deferred Income Taxes1		--		1,014		1,014	asset lives
North Dakota Renewable Resource Rider Accrued Revenues2		1,319		482		1,801		15
Big Stone II Unrecovered Project Costs – South Dakota2		100		543		643		77
Minnesota Deferred Rate Case Expenses Subject to Recovery1		1,082		--		1,082		12
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		--		568		568		24
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		73		141		214		14
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		113		--		113		12
Minnesota Renewable Resource Rider Accrued Revenues2		34		--		34		9
Total Regulatory Assets	$	21,297	$	132,094	$	153,391
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	80,404	$	80,404	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		757		--		757		12
Minnesota Environmental Cost Recovery Rider Accrued Refund		139		--		139		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,381		782		2,163		24
Deferred Income Taxes		--		818		818	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		208		919		16
South Dakota Environmental Cost Recovery Rider Accrued Refund		285		--		285		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		132		132		24
Other		21		89		110		204
Total Regulatory Liabilities	$	3,294	$	82,433	$	85,727
Net Regulatory Asset Position	$	18,003	$	49,661	$	67,664

¹Costs subject to recovery without a rate of return.

²Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

All Deferred Marked-to-Market Losses recorded as of September 30, 2017 relate to forward purchases of energy scheduled for delivery through December 2020.

The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

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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 180 months.

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2017.

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 Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.

The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of September 30, 2017.

The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of September 30, 2017.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016.

The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

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 are refundable to Minnesota customers as of September 30, 2017.

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 projectthat are refundable to Minnesota customers as of September 30, 2017.

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, 2017.

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 are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.

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, 2017.

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, 2017.

The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of September 30, 2017.

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If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.

5. Open Contract Positions 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 following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of September 30, 2017 and December 31, 2016:

(in thousands)	September 30, 2017			December 31, 2016
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	--		$	--
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(13,591	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(13,591	)	$	(17,382	)

The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2017 and December 31, 2016:

(in thousands)	September 30, 2017		December 31, 2016
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--	$	--
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1		13,591		17,382
Total Loss Contracts based on Current Market Values	$	13,591	$	17,382
1Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade	$	13,591	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		--		--
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	13,591	$	17,382

6. 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 Income/(Loss)			Total Common Equity
Balance, December 31, 2016	$	196,741		$	337,684		$	139,479		$	(3,800	)	$	670,104
Common Stock Issuances, Net of Expenses		1,285			3,684									4,969
Common Stock Retirements		(239	)		(1,560	)								(1,799	)
Net Income								54,097						54,097
Other Comprehensive Income											341			341
Employee Stock Incentive Plans Expense					2,765									2,765
Common Dividends ($0.96 per share)								(37,958	)					(37,958	)
Balance, September 30, 2017	$	197,787		$	342,573		$	155,618		$	(3,459	)	$	692,519

Shelf Registration and Common Share Distribution Agreement

The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018.

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On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.

Common Shares

Following is a reconciliation of the Company’s common shares outstanding from December 31, 2016 through September 30, 2017:

Common Shares Outstanding December 31, 2016	39,348,136
Issuances:
Executive Stock Performance Awards (2014 shares earned)	89,291
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	68,235
Cash Invested	29,463
Vesting of Restricted Stock Units	22,225
Restricted Stock Issued to Directors	17,600
Employee Stock Ownership Plan	14,835
Employee Stock Purchase Plan:
Dividends Reinvested	9,566
Cash Invested	5,284
Directors Deferred Compensation	560
Retirements:
Shares Withheld for Individual Income Tax Requirements	(47,704	)
Common Shares Outstanding September 30, 2017	39,557,491

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three- and nine-month periods ended September 30, 2017 and 2016. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:

	Three Months ended September 30				Nine Months ended September 30
	2017		2016		2017		2016
Weighted Average Common Shares Outstanding – Basic		39,507,581		38,832,659		39,440,416		38,316,324
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		211,996		103,084		195,869		80,450
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		55,975		48,645		54,645		42,620
Nonvested Restricted Shares		16,982		18,029		18,923		14,556
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,832		3,289		3,009		3,451
Total Dilutive Shares		287,785		173,047		272,446		141,077
Weighted Average Common Shares Outstanding – Diluted		39,795,366		39,005,706		39,712,862		38,457,401

The effect of dilutive shares on earnings per share for the three- and nine-month periods ended September 30, 2017 and 2016, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

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7. Share-Based Payments

Stock Incentive Awards

The following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine-month period ended September 30, 2017:

Award	Grant-Date	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Stock Performance Awards Granted to Executive Officers	February 2, 2017		59,500	$	31.00	December 31, 2019
Restricted Stock Units Granted to Executive Officers	February 2, 2017		15,900	$	37.65	25% per year through February 6, 2021
Restricted Stock Units Granted to Key Employees	April 10, 2017		9,995	$	32.78	100% on April 8, 2021
	September 25, 2017		1,000	$	38.29	100% on April 8, 2021
Restricted Stock Granted to Nonemployee Directors	April 10, 2017		17,600	$	37.75	25% per year through April 8, 2021

Under the performance share awards, the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are no voting or dividend rights related to the performance shares until common shares, if any, are issued at the end of the performance measurement period. The amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event. The vesting of these performance awards is accelerated and paid at target in the event of a change in control, disability or death and on retirement at or after age 62 for certain officers who are parties to executive employment agreements with the Company. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and recognized over the grantee’s requisite service period based on the grant-date fair value of the award.

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 share of the Company’s common stock on the date of grant.The grant-date fair value of each restricted stock unit granted to a key employee that is not an executive officer was based on the average of the high and low market price of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the respective vesting periods.

The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price of one share of the Company’s common stock on the date of grant.

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, 2017 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.9 million (before income taxes) which will be amortized over a weighted-average period of 2.2 years.

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Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three- and nine-month periods ended September 30, 2017 and 2016 are presented in the table below:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Stock Performance Awards Granted to Executive Officers	$	494	$	455	$	1,568	$	1,296
Restricted Stock Units Granted to Executive Officers		104		64		472		373
Restricted Stock Granted to Executive Officers		16		22		54		73
Restricted Stock Granted to Nonemployee Directors		144		128		416		363
Restricted Stock Units Granted to Key Employees		87		62		255		207
Employee Stock Purchase Plan (15% discount)		--		47		--		135
Totals	$	845	$	778	$	2,765	$	2,447

8. Retained Earnings Restriction

The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP debt 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 meet certain financial covenants. As of September 30, 2017 the Company was in compliance with these financial covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2016 for further information on the covenants.

Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.4% and 58.0% based on OTP’s 2017 capital structure petition approved by order of the MPUC on September 1, 2017. As of September 30, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 51.8% and its net assets restricted from distribution totaled approximately $462,000,000. Total capitalization for OTP cannot currently exceed $1,178,024,000.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2016 OTP had commitments under contracts extending into 2019, including its share of construction program commitments, totaling approximately $84.8 million. At September 30, 2017 OTP had commitments under contracts extending into 2019, including its share of construction program commitments, totaling approximately $82.6 million.

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 2040. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of 2019 and 2040, respectively. In the first quarter of 2017a portion of the coal supply for Big Stone Plant contracted for delivery in 2016 was rolled into 2018and some additional coal was contracted for delivery in 2018 and 2019. These arrangements result in an additional commitment for the purchase of coal in 2018 and 2019 totaling approximately $3.0 million. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement, but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement.

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Operating Leases

OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.

Contingencies

OTP had a $2.7 million refund liability on its balance sheet as of December 31, 2016 representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. In the February and June 2017 MISO billings, MISO processed the refund of the FERC-ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million as of December 31, 2016 to $1.6 million as of September 30, 2017.

Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to not resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. The D.C. Circuithas set a briefing schedule with final briefs due in January 2018. MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have a material effect on the Company’s results of operations.

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. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

In 2014 the Environmental Protection Agency (EPA) published both proposed standards of performance for carbon dioxide (CO2) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed CO2 emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. Both rules were challenged on legal grounds. On February 9, 2016 the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on September 27, 2016 before the full court, and a decision was expected in the first half of 2017. However, pursuant to Executive Order 13783, Promoting Energy Independence and Economic Growth, the EPA was directed to consider suspending, revising or rescinding the CO2 rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On October 16, 2017 the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.

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, 2017 will not be material.

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10. Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of September 30, 2017 and December 31, 2016:

(in thousands)	Line Limit		In Use on September 30, 2017		Restricted due to Outstanding Letters of Credit		Available on September 30, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	1,417	$	--	$	128,583	$	130,000
OTP Credit Agreement		170,000		102,220		300		67,480		127,067
Total	$	300,000	$	103,637	$	300	$	196,063	$	257,067

On October 31, 2017 both credit agreements were amended to extend the expiration dates by one year from October 29, 2021 to October 31, 2022.

Debt Retirements

On February 5, 2016 the Company borrowed $50 million under a Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points.The Company repaid $35.0 million of the $50 million in the fourth quarter of 2016 and made additional repayments of $3.0 million in January 2017, $3.0 million in June 2017 and $9.0 million on August 7, 2017. As of September 30, 2017 the Company had no borrowings under the Term Loan Agreement.

On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire its $33 million 5.95%, Series A Senior Unsecured Notes, which matured on August 20, 2017.

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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, 2017 and December 31, 2016:

September 30, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	102,220	$	1,417	$	103,637
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				47		47
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				723		723
Total	$	412,000	$	80,770	$	492,770
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		197		197
Unamortized Long-Term Debt Issuance Costs		1,687		480		2,167
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,313	$	80,093	$	490,406
Total Short-Term and Long-Term Debt (with current maturities)	$	512,533	$	81,707	$	594,240

December 31, 2016 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	42,883	$	--	$	42,883
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	15,000	$	15,000
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
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				106		106
PACE Note, 2.54%, due March 18, 2021				836		836
Total	$	445,000	$	95,942	$	540,942
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,970		231		33,201
Unamortized Long-Term Debt Issuance Costs		1,861		539		2,400
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,169	$	95,172	$	505,341
Total Short-Term and Long-Term Debt (with current maturities)	$	486,022	$	95,403	$	581,425

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11. Pension Plan and Other Postretirement Benefits

Pension Plan—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			2016
Service Cost—Benefit Earned During the Period	$	1,407		$	1,376		$	4,221		$	4,139
Interest Cost on Projected Benefit Obligation		3,534			3,603			10,604			10,646
Expected Return on Assets		(4,807	)		(4,857	)		(14,421	)		(14,590	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			48			89			142
From Other Comprehensive Income1		1			1			3			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,411			3,818			3,865
From Other Comprehensive Income1		31			32			94			95
Net Periodic Pension Cost	$	1,469		$	1,614		$	4,408		$	4,300

¹Corporate cost included in Other Nonelectric Expenses. 

Cash flows—The Company currently is not required and does not anticipate making a contribution to its pension plan in 2017. The Company made a discretionary plan contribution totaling $10.0 million in January 2016.

Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2017		2016		2017		2016
Service Cost—Benefit Earned During the Period	$	73	$	63	$	218	$	189
Interest Cost on Projected Benefit Obligation		421		417		1,264		1,251
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4		12		12
From Other Comprehensive Income1		10		9		29		28
Amortization of Net Actuarial Loss:
From Regulatory Asset		70		74		213		220
From Other Comprehensive Income2		110		111		330		334
Net Periodic Pension Cost	$	688	$	678	$	2,066	$	2,034
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and MaintenanceExpenses	$	4	$	3	$	12	$	11
Other Nonelectric Expenses		6		6		17		17
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	67	$	68	$	199	$	204
Other Nonelectric Expenses		43		43		131		130

Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			2016
Service Cost—Benefit Earned During the Period	$	357		$	365		$	1,069		$	976
Interest Cost on Projected Benefit Obligation		678			794			2,034			1,877
Amortization of Prior-Service Cost:
From Regulatory Asset		--			34			--			100
From Other Comprehensive Income1		--			1			--			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			284			699			284
From Other Comprehensive Income1		5			7			17			7
Net Periodic Postretirement Benefit Cost	$	1,273		$	1,485		$	3,819		$	3,247
Effect of Medicare Part D Subsidy	$	(141	)	$	(177	)	$	(421	)	$	(692	)
1Corporate cost included in Other Nonelectric Expenses.

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12. 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—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2017 and December 31, 2016 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.

Long-Term Debt including Current Maturities—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.

	September 30, 2017						December 31, 2016
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents		826			826			--			--
Short-Term Debt		(103,637	)		(103,637	)		(42,883	)		(42,883	)
Long-Term Debt including Current Maturities		(490,603	)		(543,870	)		(538,542	)		(583,835	)

14. 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)	2017			2016			2017			2016
Income Before Income Taxes – Continuing Operations	$	24,808		$	19,757		$	73,314		$	60,378
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		9,675			7,705			28,592			23,547
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,349	)		(1,423	)		(5,411	)		(4,994	)
Section 199 Domestic Production Activities Deduction		(330	)		(9	)		(990	)		(207	)
Excess Tax Deduction – 2014 Performance Share Awards		--			--			(697	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)		(637	)		(637	)
Corporate-Owned Life Insurance		(118	)		(92	)		(620	)		(664	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(157	)		(517	)		(472	)
R&D Tax Credits		(148	)		(223	)		(454	)		(445	)
Investment Tax Credits		(41	)		(87	)		(122	)		(262	)
Other Items – Net		(270	)		(339	)		151			(128	)
Income Tax Expense – Continuing Operations	$	7,035		$	5,163		$	19,295		$	15,738
Effective Income Tax Rate – Continuing Operations		28.4	%		26.1	%		26.3	%		26.1	%

The following table summarizes the activity related to our unrecognized tax benefits:

(in thousands)	2017			2016
Balance on January 1	$	891		$	468
Increases Related to Tax Positions for Prior Years		28			40
Increases Related to Tax Positions for Current Year		220			26
Uncertain Positions Resolved During Year		(206	)		(97	)
Balance on September 30	$	933		$	437

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The balance of unrecognized tax benefits as of September 30, 2017 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2017 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of September 30, 2017.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2017, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2014 for federal and North Dakota state income taxes and prior to 2013 for Minnesotastate income taxes.

16. Discontinued Operations

Included in discontinued operations are activities related to the Company’s former wind tower manufacturing, dock and boatlift and construction companies. Included in liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:

(in thousands)	2017			2016
Warranty Reserve Balance, January 1	$	1,369		$	2,103
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(112	)		(24	)
Decrease in Warranty Estimates for Prior Years		(400	)		(530	)
Warranty Reserve Balance, September 30	$	857		$	1,549

The warranty reserve balances as of September 30, 2017 relate to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated net income and financial condition.

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Item 2.      Management's Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

Following is an analysis of the operating results of Otter Tail Corporation (the Company, we, us and our) by business segment for the three and nine months ended September 30, 2017 and 2016, followed by a discussion of changes in our consolidated financial position during the nine months ended September 30, 2017 and our business outlook for the remainder of 2017.

Comparison of the Three Months Ended September 30, 2017 and 2016

Consolidated operating revenues were $216.5 million for the three months ended September 30, 2017 compared with $197.2 million for the three months ended September 30, 2016. Operating income was $31.6 million for the three months ended September 30, 2017 compared with $27.3 million for the three months ended September 30, 2016. The Company recorded diluted earnings per share from continuing operations of $0.45 for the three months ended September 30, 2017 compared with $0.37 for the three months ended September 30, 2016, and total diluted earnings per share of $0.45 for the three months ended September 30, 2017 compared with $0.37 for the three months ended September 30, 2016.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the three month periods ended September 30, 2017 and 2016 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2017			September 30, 2016
Operating Revenues:
Electric	$	5		$	11
Nonelectric		--			--
Costs of Products Sold		8			--
Other Nonelectric Expenses		(3	)		11

Electric

	Three Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Retail Sales Revenues	$	88,953	$	87,755	$	1,198			1.4
Wholesale Revenues – Company Generation		1,549		1,656		(107	)		(6.5	)
Other Revenues		12,897		13,312		(415	)		(3.1	)
Total Operating Revenues	$	103,399	$	102,723	$	676			0.7
Production Fuel		16,096		14,789		1,307			8.8
Purchased Power – System Use		13,371		11,473		1,898			16.5
Other Operation and Maintenance Expenses		36,570		36,207		363			1.0
Depreciation and Amortization		13,157		13,408		(251	)		(1.9	)
Property Taxes		3,721		3,506		215			6.1
Operating Income	$	20,484	$	23,340	$	(2,856	)		(12.2	)
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,060,858		1,095,236		(34,378	)		(3.1	)
Wholesale kwh Sales – Company Generation		57,400		61,244		(3,844	)		(6.3	)
Heating Degree Days		37		23		14			(60.9	)
Cooling Degree Days		284		317		(33	)		(10.4	)

The following table shows cooling degree days as a percent of normal:

	Three Months ended September 30,
	2017			2016
Cooling Degree Days		80.2	%		89.5	%

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The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the third quarters of 2017 and 2016 and between the quarters:

	Three Months ended September 30,
	2017 vs Normal			2016 vs Normal			2017 vs 2016
Effect on Diluted Earnings Per Share	$	(0.014	)	$	(0.008	)	$	(0.006	)

The $1.2 million increase in retail electric revenue includes:

● A $3.3 million increase in retail revenue related to the recovery of increased fuel and purchased power costs due to a 43.2% increase in kwhs purchased and a 12.8% increase in fuel costs per kwh generated to serve retail customers, partially offset by an 18.6% decrease in the price per kwh purchased.

● A $0.3 million increase in revenue related to the recovery of increased Conservation Improvement Program (CIP) costs.

offset by:

● A $1.4 million net decrease in interim rate revenues, Environmental Costs Recovery (ECR) rider revenues and Transmission Cost Recovery (TCR) rider revenues. This is mainly due to a true up for the lower return on equity (ROE) and other components granted by the Minnesota Public Utilities Commission in its final order in Otter Tail Power Company’s (OTP's) 2016 Minnesota general rate caseand for items included in OTP’s final compliance filing, filed during the third quarter of 2017.

● A $0.6 million decrease in revenue related to a 3.1% decrease in retail kwh sales, mostly to industrial customers.

● A $0.4 million decrease in revenues due to lower electricity usage due to the 10.4% decrease in cooling degree days between the quarters.

Other electric revenues decreased as a result of a $0.4 million decrease in integrated transmission service revenues.

Production fuel costs increased $1.3 million as a result of a 10.1% increase in the cost of fuel per kwh generated from our steam-powered and combustion turbine generators. The increase in fuel costs and the cost of fuel per kwh generated was due to an increase in kwhs generated from OTP’s higher-fuel-cost Hoot Lake Plantand an increase in the fuel cost per kwh generated at Coyote Station.

The cost of purchased power to serve retail customers increased $1.9 million as a result of a 43.2% increase in kwhs purchased, offset by an 18.6% decrease in the cost per kwh purchased.

The $0.4 million increase in other electric operation and maintenance expenses includes:

● A $0.9 million increase in labor and benefit expenses mostly related to higher medical expenses and increased post-retirement medical benefit costs.

● A $0.3 million increase in CIP expenditures.

● A $0.2 million increase in software licensing and subscription expenses.

offset by:

● A $1.0 million reduction in storm damage repair expenses compared to the third quarter of 2016, mostly associated with excessive storm damage from a large storm in July 2016 in the Bemidji service area.

Depreciation and amortization expense decreased $0.3 million as a result of extending the depreciable lives of certain assets and other assets reaching the end of their depreciable lives in 2016.

Property tax expense increased $0.2 million mainly due to transmission line additions in South Dakota related to the construction of the Big Stone South-Ellendale and Big Stone South-Brookings 345 kV transmission lines.

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Manufacturing

	Three Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Operating Revenues	$	54,355	$	52,171	$	2,184			4.2
Cost of Products Sold		41,638		40,616		1,022			2.5
Operating Expenses		6,161		5,246		915			17.4
Depreciation and Amortization		3,780		3,927		(147	)		(3.7	)
Operating Income	$	2,776	$	2,382	$	394			16.5

The $2.2 million increase in revenues in our Manufacturing segment includes the following:

● Revenues at BTD Manufacturing, Inc. (BTD), our custom metal fabricator, increased $1.4 million as a result of increased product sales from BTD’s Illinois and Georgia manufacturing facilitiesand an increase in scrap revenues due to increased volume and higher scrap-metal prices.

● Revenues at T.O. Plastics, Inc. (T.O. Plastics), our manufacturer of thermoformed plastic and horticultural products, increased $0.8 million, including increases of $0.5 million from sales of life science products and $0.2 million from sales of industrial products.

The $1.0 million increase in cost of products sold in our Manufacturing segment includes the following:

● Cost of products sold at BTD increased $0.4 million due to the increase in sales.

● Cost of products sold at T.O. Plastics increased $0.6 million due to the increase in sales.

At BTD, operating expenses increased $0.7 million. T.O. Plastics operating expenses increased $0.1 million.

Depreciation and amortization expense decreased $0.1 million at BTD as a result of certain assets becoming fully amortized.

Plastics

	Three Months Ended
	September 30,						%
(in thousands)	2017		2016		Change		Change
Operating Revenues	$	58,708	$	42,292	$	16,416		38.8
Cost of Products Sold		44,600		34,789		9,811		28.2
Operating Expenses		3,083		2,346		737		31.4
Depreciation and Amortization		976		970		6		(0.6	)
Operating Income	$	10,049	$	4,187	$	5,862		140.0

Plastics segment revenues increased $16.4 million as a result of a 22.9% increase in pounds of polyvinyl chloride (PVC) pipe sold and a 13.0% increase in PVC pipe prices between the quarters. This was a result of higher customer demand in general, but also due to customer anticipation of raw material and product supply shortages related to the August 2017 hurricanes that affected the Gulf Coast region of the United Stateswhere the major U.S. resin production plants are located. The increase in revenue more than offset the $9.8 million increase in cost of products sold due to the increased sales volumes and a 4.4% increase in the cost per pound of PVC pipe sold. Operating expenses increased due to increased incentives and commissions directly related to the increase in pipe sales. Hurricane Harvey had a significant impact on market conditions for September. Major resin suppliers shut down production facilities which impacted raw material availability. This created concerns of pipe availability by distributors and contractors which resulted in accelerated pipe demand and created positive sales price pressure in the market. The estimated impact of this event on third quarter 2017 results is $2.8 million in operating income and $1.7 million or $0.04 per diluted share in earnings.Even though Hurricane Harvey impacted raw material availability, we had sufficient raw materials in September to run our plants and meet the additional demand.

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Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

	Three Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Operating Expenses	$	1,686	$	2,616	$	(930	)		(35.6	)
Depreciation and Amortization		14		9		5			55.6

Corporate operating expenses decreased $0.9 million, mainly as a result of decreases in salary, benefit and insurance costsand equipment repair expenses.

Interest Charges

The $0.6 million decrease in interest charges in the three months ended September 30, 2017 compared with the three months ended September 30, 2016 is related to lower cost debt resulting from the issuance of $80.0 million of our 3.55% Guaranteed Senior Notes and the retirement of our remaining $52.3 million outstanding 9.000% Notes in December 2016 and OTP’s $33.0 million outstanding 5.95%, Series A Senior Unsecured Notes at maturity on August 20, 2017. The average level of debt outstanding between the quarters was essentially unchanged.

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $1.9 million in the three months ended September 30, 2017 compared with the three months ended September 30, 2016 mainly as a result of a $5.1 million increase in income from continuing operations before income taxes. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on our consolidated statements of income for the three month periods ended September 30, 2017 and 2016:

(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	24,808		$	19,757
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		9,675			7,705
Increases (Decreases) in Tax from:
Federal Production Tax Credits (PTCs)		(1,349	)		(1,423	)
Section 199 Domestic Production Activities Deduction		(330	)		(9	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(157	)
R&D Tax Credits		(148	)		(223	)
Corporate-Owned Life Insurance		(118	)		(92	)
Allowance for Funds Used During Construction - Equity		(92	)		(51	)
Investment Tax Credits		(41	)		(87	)
Other Items – Net		(178	)		(288	)
Income Tax Expense – Continuing Operations	$	7,035		$	5,163
Effective Income Tax Rate – Continuing Operations		28.4	%		26.1	%

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

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Comparison of the Nine Months Ended September 30, 2017 and 2016

Consolidated operating revenues were $642.7 million for the nine months ended September 30, 2017 compared with $606.9 million for the nine months ended September 30, 2016. Operating income was $94.0 million for the nine months ended September 30, 2017 compared with $81.9 million for the nine months ended September 30, 2016. The Company recorded diluted earnings per share from continuing operations of $1.36 for the nine months ended September 30, 2017 compared with $1.16 for the nine months ended September 30, 2016, and total diluted earnings per share of $1.36 for the nine months ended September 30, 2017 compared with $1.17 for the nine months ended September 30, 2016.

Amounts presented in the segment tables that follow for operating revenues, cost of products sold and other nonelectric operating expenses for the nine month periods ended September 30, 2017 and 2016 will not agree with amounts presented in the consolidated statements of income due to the elimination of intersegment transactions. The amounts of intersegment eliminations by income statement line item are listed below:

Intersegment Eliminations (in thousands)	September 30, 2017		September 30, 2016
Operating Revenues:
Electric	$	18	$	27
Nonelectric		--		--
Costs of Products Sold		11		--
Other Nonelectric Expenses		7		27

Electric

	Nine Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Retail Sales Revenues	$	280,423	$	274,395	$	6,028			2.2
Wholesale Revenues – Company Generation		3,600		3,426		174			5.1
Other Revenues		40,163		35,821		4,342			12.1
Total Operating Revenues	$	324,186	$	313,642	$	10,544			3.4
Production Fuel		44,955		40,479		4,476			11.1
Purchased Power – System Use		48,935		43,486		5,449			12.5
Other Operation and Maintenance Expenses		112,799		115,206		(2,407	)		(2.1	)
Depreciation and Amortization		39,317		40,323		(1,006	)		(2.5	)
Property Taxes		11,228		10,774		454			4.2
Operating Income	$	66,952	$	63,374	$	3,578			5.6
Electric kwh Sales (in thousands)
Retail kwh Sales		3,524,468		3,517,153		7,315			0.2
Wholesale kwh Sales – Company Generation		141,642		141,817		(175	)		(0.1	)
Heating Degree Days		3,539		3,277		262			8.0
Cooling Degree Days		380		450		(70	)		(15.6	)

The following table shows heating and cooling degree days as a percent of normal:

	Nine Months ended September 30,
	2017			2016
Heating Degree Days		88.7	%		82.1	%
Cooling Degree Days		82.4	%		97.6	%

The following table summarizes the estimated effect on diluted earnings per share of the difference in retail kwh sales under actual weather conditions and expected retail kwh sales under normal weather conditions in the first nine months of 2017 and 2016 and between the periods:

	Nine Months ended September 30,
	2017 vs Normal			2016 vs Normal			2017 vs 2016
Effect on Diluted Earnings Per Share	$	(0.043	)	$	(0.050	)	$	0.007

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The $6.0 million increase in retail electric revenue includes:

● A $9.7 million increase in retail revenue related to the recovery of increased fuel and purchased power costs due to a 7.7% increase in fuel costs per kwh generated and a 6.4% increase in the price per kwh purchased to serve retail customers.

● A $2.5 million increase in retail revenue (net of a $2.3 million increase in the refund accrual) related to an interim rate increase implemented in April 2016 in conjunction with OTP's 2016 general rate increase request in Minnesota.

● A $0.4 million increase in revenues mainly related to increased consumption due to colder weather in the first nine months of 2017, evidenced by a 8.0% increase in heating degree days between the periods.

offset by:

● A $3.3 million decrease in ECR rider revenue mainly due to a decrease in the unrecovered balance of environmental upgrades due to depreciation and also due to a reduction in the allowed ROE component of the Minnesota ECR related to the lower ROE granted in OTP's 2016 Minnesota general rate case.

● A $1.3 million decrease in Minnesota TCR rider revenues due to an increase in MISO tariff revenues subject to refund through the rider and a reduction in the allowed ROE component of the Minnesota TCR related to the lower ROE granted in OTP's 2016 Minnesota general rate case.

● A $0.9 million decrease in Minnesota CIP incentive revenues due to a reduction in the incentive rate in 2017.

● A $0.8 million negative price variance related to increased sales of electricity to customers receiving service under lower tariff rates.

● A $0.3 million decrease in North Dakota Renewable Resource Adjustment rider revenues mainly due to increasing PTCs applied against the rider revenue requirement.

The $4.3 million increase in other electric revenues includes a $3.5 million increase in transmission tariff revenues related to increased investment in regional transmission lines and a $0.7 million increase in interconnection revenues related to another generator's new wind project that began generating electricity in November 2016.

Production fuel costs increased $4.5 million as a result of a 4.0% increase in kwhs generated combined with a 6.8% increase in the cost of fuel per kwh generated from our steam-powered and combustion turbine generators. The increase in generation was mainly at Coyote Station, which was down for maintenance for 10 weeks during the first nine months of 2016 compared to being down for maintenance for just two weeks in August of 2017. The increase in fuel costs per kwh of generation was mainly at Coyote Station, which began taking coal under a new supply agreement in May 2016, but also due to an 11.3% increase in generation from OTP’s higher-fuel-cost Hoot Lake Plant.

The cost of purchased power to serve retail customers increased $5.4 million as a result a 5.7% increase in kwhs purchased, and a 6.4% increase in the cost per kwh purchased due to higher market prices and increased prices for energy purchases under a long-term contract.

Other electric operation and maintenance expenses decreased $2.4 million as a result of:

● A $2.0 million reduction in external service costs due to a decrease in costs related to the Coyote Creek Coal Mine tie-in project completed in the second quarter of 2016.

● A $1.8 million decrease in Midcontinent Independent System Operator, Inc. (MISO) transmission service charges mainly due to a refund received in February 2017 related to a reduction in the ROE component of the MISO tariff from 12.38% to 10.82% from November 2013 through January 2015.The benefits of this refund are passed back to retail ratepayers through state transmission cost recovery rider adjustments.

● A $1.3 million reduction in storm damage repair expenses mostly associated with excessive storm damage from a large storm in July 2016 in the Bemidji service area.

offset by:

● A $1.2 million increase in benefit expenses related to higher medical expenses and increased post-retirement medical benefit costs.

● A $1.0 million increase in labor costs mainly related to overtime work required to respond to storm outages and to conduct load research and applications development to improve system operations.

● A $0.5 million increase in material and supplies expense related to power plant and distribution system maintenance.

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Depreciation and amortization expense decreased $1.0 million as a result of extending the depreciable lives of certain assets and as a result of other assets reaching the end of their depreciable lives in 2016.

Property taxes increased $0.5 million mainly due to transmission line additions in South Dakota related to the construction of the Big Stone South-Ellendale and Big Stone South-Brookings 345 kV transmission lines.

Manufacturing

	Nine Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Operating Revenues	$	172,076	$	170,443	$	1,633			1.0
Cost of Products Sold		131,401		129,929		1,472			1.1
Operating Expenses		17,583		16,581		1,002			6.0
Depreciation and Amortization		11,511		11,891		(380	)		(3.2	)
Operating Income	$	11,581	$	12,042	$	(461	)		(3.8	)

The $1.6 million increase in revenues in our Manufacturing segment includes the following:

● Revenues at BTD decreased $0.5 million due to a reduction in tooling revenues that was partially offset by increased product sales.

● Revenues at T.O. Plastics increased $2.1 million, including a $1.1 million increase in revenue from sales of life science products due to an expanding customer base and sales of new product, a $0.5 million increase in revenue from sales of horticultural containers, and a $0.5 million increase in revenue from sales of other products, mainly to industrial customers.

The $1.5 million increase in cost of products sold in our Manufacturing segment includes the following:

● Cost of products sold at BTD increased $0.2 million. An increase in costs related to increased product sales volume andincreased costs for scrapped parts and obsolete inventory was mostly offset by a reduction in tooling costs related to less tooling work and lower tooling revenues.

● Cost of products sold at T.O. Plastics increased $1.3 million as a result of the increase in product sales, partially mitigated bylower raw material costs due to more favorable resin prices in 2017.

The $1.0 million increase in Manufacturing segment operating expenses includes the following:

● Operating expense at BTD increased $0.8 million, including a $0.5 million increase in insurance expense and a $0.3 million increase in property taxes.

● Operating expense at T.O. Plastics increased $0.2 million, mainly due to increased sales and incentive costs related to its development of new markets and expanded sales of life science products.

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Plastics

	Nine Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Operating Revenues	$	146,416	$	122,841	$	23,575			19.2
Cost of Products Sold		114,130		99,064		15,066			15.2
Operating Expenses		7,816		6,958		858			12.3
Depreciation and Amortization		2,830		2,880		(50	)		(1.7	)
Operating Income	$	21,640	$	13,939	$	7,701			55.2

Plastics segment revenues increased $23.6 million as a result of a 10.2% increase in pounds of PVC pipe sold and an 8.2% increase in the price per pound sold between the periods. This was a result of higher customer demand year over year, but also due to customer anticipation of raw material and product supply shortages following the August 2017 hurricanes that affected the Gulf Coast region of the United Stateswhere the major U.S. resin production plants are located. The increase in revenue more than offset the $15.1 million increase in cost of products sold related to the increased sales volumes and a 4.6% increase in the cost per pound of PVC pipe sold. Operating expenses increased due to increased incentives and commissions directly related to the increase in pipe sales. Hurricane Harvey had a significant impact on market conditions for September. Major resin suppliers shut down production facilities which impacted raw material availability. This created concerns of pipe availability by distributors and contractors which resulted in accelerated pipe demand and created positive sales price pressure in the market. The estimated impact of this event on September 2017 year-to-date results is $2.8 million in operating income and $1.7 million or $0.04 per diluted share in earnings.Even though Hurricane Harvey impacted raw material availability, we had sufficient raw materials in September to run our plants and meet the additional demand.

Corporate

Corporate includes items such as corporate staff and overhead costs, the results of our captive insurance company and other items excluded from the measurement of operating segment performance. Corporate is not an operating segment. Rather it is added to operating segment totals to reconcile to totals on our consolidated statements of income.

	Nine Months Ended
	September 30,							%
(in thousands)	2017		2016		Change			Change
Operating Expenses	$	6,143	$	7,378	$	(1,235	)		(16.7	)
Depreciation and Amortization		31		34		(3	)		(8.8	)

Corporate operating expenses decreased $1.2 million as a result of a $0.4 million decrease in contracted service expenses, a $0.4 million decrease in labor costs due to a reduction in employees, a $0.2 million increase in corporate costs allocated to the Electric segment as a result of an increase in the segment’s proportional share of consolidated revenues and assets, and a $0.2 million reduction in insurance and maintenance expenses.

Interest Charges

The $1.6 million decrease in interest charges in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 is related to lower cost debt resulting from the issuance of $80.0 million of our 3.55% Guaranteed Senior Notes and the retirement of our remaining $52.3 million outstanding 9.000% Notes in December 2016and OTP’s $33.0 million outstanding 5.95%, Series A Senior Unsecured Notes at maturity on August 20, 2017. The average level of debt outstanding between the periods was essentially unchanged.

Other Income

Other income decreased $0.7 million in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016, mainly as a result of the receipt of $0.7 million in nontaxable corporate-owned life insurance benefit proceeds in the second quarter of 2016 while no similar benefit proceeds were received in the first nine months of 2017.

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Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $3.6 million in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 mainly as a result of a $12.9 million increase in income from continuing operations before income taxes, offset by (1) $0.7 million in excess tax benefits related to the accounting treatment of stock performance awards, and (2) a $0.8 million increase in federal Section 199 Domestic Production Activities Deductions related to products our companies produce in the United States. The following table provides a reconciliation of income tax expense calculated at our net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on our consolidated statements of income for the nine month periods ended September 30, 2017 and 2016:

(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	73,314		$	60,378
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		28,592			23,547
Increases (Decreases) in Tax from:
Federal PTCs		(5,411	)		(4,994	)
Section 199 Domestic Production Activities Deduction		(990	)		(207	)
Excess Tax Deduction – 2014 Performance Share Awards		(697	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(637	)		(637	)
Corporate-Owned Life Insurance		(620	)		(664	)
Employee Stock Ownership Plan Dividend Deduction		(517	)		(472	)
R&D Tax Credits		(454	)		(445	)
Investment Tax Credits		(122	)		(262	)
Other Items – Net		151			(128	)
Income Tax Expense – Continuing Operations	$	19,295		$	15,738
Effective Income Tax Rate – Continuing Operations		26.3	%		26.1	%

Federal PTCs are recognized as wind energy is generated based on a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased 2.3% in the nine months ended September 30, 2017 compared with the nine months ended September 30, 2016 due to improved availability of the turbines and more favorable wind and operating conditions in the first nine months of 2017. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are being recognized on a straight-line basis over 25 years.

Financial Position

The following table presents the status of our lines of credit as of September 30, 2017 and December 31, 2016:

(in thousands)	Line Limit		In Use on September 30, 2017		Restricted due to Outstanding Letters of Credit		Available on September 30, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	1,417	$	--	$	128,583	$	130,000
OTP Credit Agreement		170,000		102,220		300		67,480		127,067
Total	$	300,000	$	103,637	$	300	$	196,063	$	257,067

We believe we have the necessary liquidity to effectively conduct business operations for an extended period if needed. Our balance sheet is strong and we are in compliance with our debt covenants. Financial flexibility is provided by operating cash flows, unused lines of credit, strong financial coverages, investment grade credit ratings and alternative financing arrangements such as leasing.

We believe our financial condition is strong and our cash, other liquid assets, operating cash flows, existing lines of credit, access to capital markets and borrowing ability because of investment-grade credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. On May 11, 2015 we filed a shelf registration statement with the Securities and Exchange Commission (SEC) under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018. On May 11, 2015, we entered into a Distribution Agreement with J.P. Morgan Securities LLC (JPMS) under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. No shares were issued under this program in the first nine months of 2017.

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Equity or debt financing will be required in the period 2017 through 2021 given the expansion plans related to our Electric segment to fund construction of new rate base investments. Also, such financing will be required should we decide to reduce borrowings under our lines of credit or refund or retire early any of our presently outstanding debt, to complete acquisitions or for other corporate purposes. Our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside our control. In addition, our borrowing costs can be impacted by changing interest rates on short-term and long-term debt and ratings assigned to us by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios.

The determination of the amount of future cash dividends to be declared and paid will depend on, among other things, our financial condition, improvement in earnings per share, cash flows from operations, the level of our capital expenditures and our future business prospects. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by our subsidiaries. See note 8 to consolidated financial statements for more information. The decision to declare a dividend is reviewed quarterly by the board of directors. On February 2, 2017 our board of directors increased the quarterly dividend from $0.3125 to $0.32 per common share.

Cash provided by operating activities of continuing operations was $114.2 million for the nine months ended September 30, 2017 compared with cash provided by operating activities of $115.1 million for the nine months ended September 30, 2016. The $0.9 million decrease in cash provided by continuing operations includes a $9.3 million increase in net income from continuing operations and a $10.0 million reduction in discretionary contributions to our funded pension plan, offset by a $19.5 million increase in cash used for working capital. The increase in cash used for working capital between the periods is primarily due to a $21.1 million increase in receivables in the first nine months of 2017 compared with only a $3.5 million increase in the first nine months of 2016, mainly as a result of a significant increase in receivables in the Plastics segment due to strong PVC pipe sales in the third quarter of 2017.

Net cash used in investing activities was $95.3 million for the nine months ended September 30, 2017 compared with $123.4 million for the nine months ended September 30, 2016. The $28.1 million decrease in cash used for investing activities includes a $31.4 million decrease in cash used for capital expenditures offset by decreases of $1.7 million in proceeds from the disposal of noncurrent assets and $1.5 million in acquisition purchase price adjustments. The decrease in cash used for capital expenditures is mainly due to a $31.6 million reduction in cash used for capital expenditures at OTP as work wound down on the Big Stone South-Brookings 345 kV transmission line project which was energized in September 2017.

Net cash used in financing activities was $18.0 million for the nine months ended September 30, 2017 compared with net cash provided by financing activities of $8.7 million for the nine months ended September 30, 2016.

Financing activities in the first nine months of 2017 included a $59.3 million increase in net short-term borrowings under OTP’s credit agreement, of which $33.0 million was used to redeem OTP’s 5.95% Senior Unsecured Series A Notes which matured on August 20, 2017. The additional short-term borrowings were used to fund a portion of OTP’s 2017 capital expenditures. Operating cash flows from our Manufacturing and Plastic’s segments were used to repay an additional $15.2 million in long-term debt related to those operations. Financing activities in the first nine months of 2017 also included $4.8 million from an increase in checks written in excess of cash and $4.3 million in net proceeds from the issuance of common stock under our automatic dividend reinvestment and share purchase plan, offset by $1.8 million in stock repurchases related to tax withholding requirements for stock incentive awards. See note 6 to the Company’s consolidated financial statements for further information on stock issuances and retirements in the first nine months of 2017. We paid $38.0 million in common stock dividends in the first nine months of 2017.

Financing activities in the first nine months of 2016 included $50 million in borrowings under a Term Loan Agreement and $39.4 million in net proceeds from the issuance of stock under the Company’s At-the-Market offering program and its automatic dividend reinvestment and share purchase plan, offset by $44.3 million in cash used to pay down short-term borrowings and checks written in excess of cash and $36.0 million in common stock dividend payments. The outstanding short-term borrowings that were paid down were, in part, used to fund the expansion of BTD’s Minnesota facilities in 2015 and the September 1, 2015 acquisition of BTD-Georgia.

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CAPITAL REQUIREMENTS

2017-2021 Capital Expenditures

The following table shows our 2016 capital expenditures and 2017 through 2021 planned capital expenditures and electric utility average rate base:

(in millions)	2016		2017		2018		2019		2020		2021
Capital Expenditures:
Electric Segment:
Transmission			$	88	$	49	$	11	$	11	$	7
Renewables and Natural Gas Generation				3		80		288		71		20
Other				44		44		47		48		51
Total Electric Segment	$	150	$	135	$	173	$	346	$	130	$	78
Manufacturing and Plastics Segments		11		14		17		15		14		14
Total Capital Expenditures	$	161	$	149	$	190	$	361	$	144	$	92
Total Electric Utility Average Rate Base			$	1,063	$	1,118	$	1,267	$	1,396	$	1,419

The capital expenditure plan for the 2017-2021 time period calls for $936 million based on the need for additional wind and solar in rate base and capital spending on a natural gas-fired plant that is expected to replace Hoot Lake Plant when it is retired in 2021. Execution on the currently anticipated electric utility capital expenditure plan is expected to grow rate base and be a key driver in increasing utility earnings over the 2017 through 2021 timeframe.

On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (EDF) to purchase and assume the development assets associated with a 150-megawatt wind farm in southeastern North Dakota (the Merricourt Project)for a purchase price of $34.7 million, subject to adjustments for interconnection costs. The Purchase Agreement is currently expected to close no earlier than mid-2018, pending regulatory reviews and other customary conditions. On the same day, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF that will be effective upon the closing of the Purchase Agreement pursuant to which EDF will construct the wind farm with a targeted completion date in 2019for consideration of $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project milestones. The agreements contain representations, warranties, covenants and indemnities customary to transactions of this type and include provisions for liquidated damages to be paid by EDF in the event of certain occurrences described in the agreements. As of September 30, 2017 OTP had capitalized approximately $4.3 million in development costs associated with the Merricourt Project. On April 10, 2017 OTP submitted an application for Advance Determination of Prudence (ADP) and Certificate of Public Convenience and Necessity to the North Dakota Public Service Commission (NDPSC) for the Merricourt Project. On October 2, 2017 OTP and the NDPSC advocacy staff filed a settlement agreement for consideration and approval of the NDPSC. A hearing held on October 6, 2017 afforded the NDPSC an opportunity to consider the application and potential approval of the settlement agreement. A final order is expected in the fourth quarter of 2017. Receipt of a satisfactory ADP by OTP is a condition to closing on the Purchase Agreement.

In addition to initiation of the Merricourt Project, OTP is moving forward with plans for the development, construction and ownership of a 250-megawatt simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota (Astoria Station) as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. OTP expects the project will cost approximately $165 million. As of September 30, 2017 OTP had capitalized approximately $3.4 million in development costs associated with Astoria Station. On April 10, 2017 OTP also submitted an application for ADP to the NDPSC for Astoria Station.The application for ADP was consolidated for hearing with the Merricourt Project ADP application hearing on October 6, 2017.

If a resource addition is determined to be prudent by the NDPSC, a public utility may recover in its rates for North Dakota customers, and in a timely manner consistent with the public utility's financial obligations, the jurisdictional share of amounts the public utility reasonably incurred or obligated on a prudent resource addition, including accrued allowance for funds used during construction, even though the resource addition may never be fully operational or used by the public utility to serve its North Dakota customers. The cost amortization period for a discontinued resource addition may not exceed five years from the date commencement of the recovery is approved by the NDPSC. No return on amounts incurred or obligated by the public utility may be authorized for the period after the resource addition is discontinued.

Contractual Obligations

Our contractual obligations for years 2018 and 2019 reported in the table on page 49 of our Annual Report on Form 10-K for the year ended December 31, 2016 increased $38.7 million in the first nine months of 2017 as a result of an increase in

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purchase obligations associated with the construction of the Big Stone South-Ellendale 345 kV Multi-Value Transmission Project (MVP) of $35.7 million and an increase in coal purchase commitments for Big Stone Plant of $3.0 million.

On August 21, 2017 OTP used borrowings under the OTP credit agreement to retire its $33 million outstanding 5.95%, Series A Senior Unsecured Notes, which matured on August 20, 2017. On December 31, 2016 we had $15.0 million outstanding under our $50 million Term Loan Agreement due February 5, 2018 that was fully repaid as of August 7, 2017.

CAPITAL RESOURCES

On May 11, 2015 we filed a shelf registration statement with the SEC under which we may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, which expires on May 11, 2018. On May 11, 2015, we entered into a Distribution Agreement with JPMS under which we may offer and sell our common shares from time to time through JPMS, as our distribution agent, up to an aggregate sales price of $75 million through an At-the-Market offering program. No shares have been sold under this program in the first nine months of 2017.

Short-Term Debt

The following table presents the status of our lines of credit as of September 30, 2017 and December 31, 2016:

(in thousands)	Line Limit		In Use on September 30, 2017		Restricted due to Outstanding Letters of Credit		Available on September 30, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	1,417	$	--	$	128,583	$	130,000
OTP Credit Agreement		170,000		102,220		300		67,480		127,067
Total	$	300,000	$	103,637	$	300	$	196,063	$	257,067

On October 29, 2012 we entered into a Third Amended and Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit Agreement. On October 31, 2017 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2021 to October 31, 2022. We can draw on this credit facility to refinance certain indebtedness and support our operations and the operations of certain of our subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to adjustment based on our senior unsecured credit ratings. We are required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement contains a number of restrictions on us and the businesses of our wholly owned subsidiary, Varistar Corporation (Varistar) and its subsidiaries, including restrictions on our and their ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties. The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our credit ratings. Our obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of our subsidiaries. Outstanding letters of credit issued by us under the Otter Tail Corporation Credit Agreement can reduce the amount available for borrowing under the line by up to $40 million.

On October 29, 2012 OTP entered into a Second Amended and Restated Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2017 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2021 to October 31, 2022. OTP can draw on this credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s obligations under the OTP Credit Agreement are not guaranteed by any other party.

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Long-Term Debt

2016 Note Purchase Agreement

On September 23, 2016 we entered into a Note Purchase Agreement (the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which we agreed to issue to the purchasers, in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15, 2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. Our obligations under the 2016 Note Purchase Agreement and the 2026 Notes are guaranteed by our Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under our Term Loan Agreement described below.

We may prepay all or any part of the 2026 Notes (in an amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by us of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. We are required to offer to prepay all of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if we and our Material Subsidiaries sell a “substantial part” of our or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the 2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement) of the 2026 Notes held by each holder of the 2026 Notes.

The 2016 Note Purchase Agreement contains a number of restrictions on the business of the Company and our Material Subsidiaries. These include restrictions on our and our Material Subsidiaries’ abilities to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or pay dividends on our and our Material Subsidiaries’ shares of capital stock, and make investments. The 2016 Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in our or our Material Subsidiaries’ credit ratings.

Term Loan Agreement

On February 5, 2016 we entered into a $50 million Term Loan Agreement (the Term Loan Agreement) that was fully paid off in August 2017.

 

2013 Note Purchase Agreement

On August 14, 2013 OTP entered into a Note Purchase Agreement (the 2013 Note Purchase Agreement) with the Purchasers named therein, pursuant to which OTP agreed to issue to the Purchasers, in a private placement transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029 (the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February 27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). On February 27, 2014 OTP issued all $150 million aggregate principal amount of the Notes.

The 2013 Note Purchase Agreement states that OTP may prepay all or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount, provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the 2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP.

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The 2013 Note Purchase Agreement contains a number of restrictions on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”), then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement, provided that no default or event of default has occurred and is continuing.

2007 and 2011 Note Purchase Agreements

On December 1, 2011, OTP issued $140 million aggregate principal amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011 (2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes, Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively, the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase Agreement). On August 21, 2017 OTP used borrowings under the OTP Credit Agreement to retire its $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, which matured on August 20, 2017.

The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants as described below under the heading “Financial Covenants.”

Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of September 30, 2017.

No Credit or Note Purchase Agreement contains any provisions that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related obligor by rating agencies.

Our borrowing agreements are subject to certain financial covenants. Specifically:

● Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, we may not permit the ratio of our Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit our Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis). As of September 30, 2017 our Interest and Dividend Coverage Ratio calculated under the requirements of the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement was 4.26 to 1.00.

● Under the 2016 Note Purchase Agreement, wemay not permit our Priority Indebtedness to exceed 10% of our Total Capitalization.

● Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00.

● Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50 to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of its Total Capitalization, as provided in the related agreement. As of September 30, 2017 OTP’s Interest and Dividend Coverage Ratio and Interest Charges Coverage Ratio, calculated under the requirements of the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, was 3.72 to 1.00.

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● Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase Agreement.

As of September 30, 2017 our ratio of Interest-bearing Debt to Total Capitalization was 0.46 to 1.00 on a consolidated basis and 0.48 to 1.00 for OTP. Neither Otter Tail Corporation or OTP had any Priority Indebtedness outstanding as of September 30, 2017.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $3.9 million, but our line of credit borrowing limits are only restricted by $0.3 million in outstanding letters of credit. We do not have any other off-balance-sheet arrangements or any relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance special purpose entities or variable interest entities, which are established for the purpose of facilitating off-balance-sheet arrangements or for other contractually narrow or limited purposes. We are not exposed to any financing, liquidity, market or credit risk that could arise if we had such relationships.

2017 BUSINESS OUTLOOK

With third quarter results exceeding our expectations for the Plastics segment, we are raising our previously announced guidance range of $1.65 to $1.80 per diluted share to $1.75 to $1.85 per diluted share. This guidance reflects the current mix of businesses we own, considers the cyclical nature of some of our businesses, and reflects current regulatory factors and economic challenges facing our Electric, Manufacturing and Plastics segments. It also reflects strategies for improving future operating results. We expect capital expenditures for 2017 to be $130 million compared with actual cash used for capital expenditures of $161 million in 2016. Planned expenditures for 2017 include investments in two large transmission line projects for the Electric segment, which positively impact earnings by providing an immediate return on invested funds through rider recovery mechanisms.

Segment components of our 2017 earnings per share guidance range compared with 2016 actual earnings are as follows:

	2016			2017 Guidance
	EPS by			February 6, 2017				August 7, 2017				November 1, 2017
Diluted Earnings Per Share	Segment			Low		High		Low		High		Low		High
Electric		$	1.29	$	1.31	$	1.34	$	1.31	$	1.34	$	1.27	$	1.29
Manufacturing		$	0.15	$	0.17	$	0.21	$	0.17	$	0.21	$	0.19	$	0.21
Plastics		$	0.27	$	0.26	$	0.30	$	0.31	$	0.35	$	0.43	$	0.45
Corporate		$	(0.11)	$	(0.14)	$	(0.10)	$	(0.14)	$	(0.10)	$	(0.14)	$	(0.10)
Total – Continuing Operations		$	1.60	$	1.60	$	1.75	$	1.65	$	1.80	$	1.75	$	1.85
Return on Equity			9.8%		9.3%		10.2%		9.7%		10.5%		10.2%		10.8%

Contributing to our earnings guidance for 2017 are the following items:

● We expect 2017 Electric segment net income to be higher than 2016 segment net income based on:

o Normal weather for the remainder of 2017. Milder than normal weather in 2016 negatively impacted diluted earnings per share by $0.07. Milder than normal weather has negatively impacted diluted earnings per share by $0.04 through the nine months ended September 30, 2017.

o A full year of increased rates compared with 8.5 months in 2016. In March 2017, the Minnesota Public Utilities Commission granted Otter Tail Power Company a revenue increase of approximately 6.2% with a 9.41% ROE.

o Rider recovery increases from transmission riders related to the Electric segment’s continuing investments in its share of the MVPs in South Dakotaoffset by declining environmental riders due to decreasing rate base.

o Increased kwh sales to industrial and commercial customers.

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offset by:

o Increased operating and maintenance expenses of $0.05 per share due to inflationary increases and increasing benefit costs. Included is an increase in pension costs as a result of a decrease in the discount rate from 4.76% to 4.60% and a decrease in the assumed long-term rate of return on plan assets from 7.75% to 7.50%.

o Higher property tax expense due to large capital projects being put into service.

o Lower CIP incentives of $0.03 per share in Minnesota as a result of program changes made by the Minnesota Department of Commerce that reduced the CIP incentive cap by 32.5% compared to 2016.

o Increased costs related to contractual price increases in certain capacity agreements.

● We expect 2017 net income from our Manufacturing segment to increase over 2016 due to:

o A slight increase in sales at BTD due to capturing new business with existing customers, higher scrap sales and higher lawn and garden end market sales.

o Improved margins on parts and tooling sales at BTD combined with lower interest costs from refinancing long-term debt at a lower interest rate in the fourth quarter of 2016.

o An increase in earnings from T.O. Plastics mainly driven by year-over-year sales growth in our horticulture, life science and industrial markets and lower interest costs from refinancing long-term debt at a lower interest rate in the fourth quarter of 2016.

o Backlog for the manufacturing companies of approximately $53 million for 2017 compared with $42 million one year ago.

● We are raising our 2017 net income expectations from the Plastics segment to be higher than our original plan and our August 2017 guidance. The reasons for this increase are:

o The strong results through the first nine months of 2017.

o The impact of Hurricane Harvey on market conditions from September through December. Harvey made landfall on August 25th. As the storm progressed, major resin suppliers shut down production facilities which impacted raw material availability. This created concerns of pipe availability by distributors and contractors which resulted in accelerated pipe demand and created positive sales price pressure in the market. When comparing the low end of the updated earnings per share range for the Plastics segment to the 2016 earnings per share, $0.08 of the increase is due to improved profitability from normal business operations and $0.08 is due to the impact of Hurricane Harvey on business conditions.

o Lower interest costs in 2017 resulting from the long-term debt refinancing completed in the fourth quarter of 2016.

● Corporate costs in 2017 are expected to be in line with 2016 costs.

Critical Accounting Policies Involving Significant Estimates

The discussion and analysis of the financial statements and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.

We use estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used for such items as depreciable lives, asset impairment evaluations, tax provisions, collectability of trade accounts receivable, self-insurance programs, unbilled electric revenues, warranty reserves and actuarially determined benefits costs and liabilities. As better information becomes available or actual amounts are known, estimates are revised. Operating results can be affected by revised estimates. Actual results may differ from these estimates under different assumptions or conditions. Management has discussed the application of these critical accounting policies and the development of these estimates with the Audit Committee of the board of directors. A discussion of critical accounting policies is included under the caption “Critical Accounting Policies Involving Significant Estimates” on pages 55 through 58 of our Annual Report on Form 10-K for the year ended December 31, 2016. There were no material changes in critical accounting policies or estimates during the quarter ended September 30, 2017.

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Forward Looking Information - Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 (the Act), we have filed cautionary statements identifying important factors that could cause our actual results to differ materially from those discussed in forward-looking statements made by or on behalf of the Company. When used in this Form 10-Q and in future filings by the Company with the Securities and Exchange Commission, in our press releases and in oral statements, words such as "may", "will", "expect", "anticipate", "continue", "estimate", "project", "believes" or similar expressions are intended to identify forward-looking statements within the meaning of the Act and are included, along with this statement, for purposes of complying with the safe harbor provision of the Act.These forward-looking statements involve risks and uncertainties. Actual results may differ materially from those contemplated by the forward-looking statements due to, among other factors, the risks and uncertainties described in the section entitled “Risk Factors” in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, as well as the various factors described below:

● Federal and state environmental regulation could require us to incur substantial capital expenditures and increased operating costs.

● Volatile financial markets and changes in our debt ratings could restrict our ability to access capital and increase borrowing costs and pension plan and postretirement health care expenses.

● We rely on access to both short- and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations. If we are unable to access capital at competitive rates, our ability to implement our business plans may be adversely affected.

● Disruptions, uncertainty or volatility in the financial markets can also adversely impact our results of operations, the ability of customers to finance purchases of goods and services, and our financial condition, as well as exert downward pressure on stock prices and/or limit our ability to sustain our current common stock dividend level.

● We could be required to contribute additional capital to the pension plan in the future if the market value of pension plan assets significantly declines, plan assets do not earn in line with our long-term rate of return assumptions or relief under the Pension Protection Act is no longer granted.

● Any significant impairment of our goodwill would cause a decrease in our asset values and a reduction in our net operating income.

● Declines in projected operating cash flows at BTD or the Plastics segment may result in goodwill impairments that could adversely affect our results of operations and financial position, as well as financing agreement covenants.

● The inability of our subsidiaries to provide sufficient earnings and cash flows to allow us to meet our financial obligations and debt covenants and pay dividends to our shareholders could have an adverse effect on us.

● We rely on our information systems to conduct our business and failure to protect these systems against security breaches or cyber-attacks could adversely affect our business and results of operations. Additionally, if these systems fail or become unavailable for any significant period of time, our business could be harmed.

● Economic conditions could negatively impact our businesses.

● If we are unable to achieve the organic growth we expect, our financial performance may be adversely affected.

● Our plans to grow and realign our business mix through capital projects, acquisitions and dispositions may not be successful, which could result in poor financial performance.

● We may, from time to time, sell assets to provide capital to fund investments in our electric utility business or for other corporate purposes, which could result in the recognition of a loss on the sale of any assets sold and other potential liabilities. The sale of any of our businesses could expose us to additional risks associated with indemnification obligations under the applicable sales agreements and any related disputes.

● Significant warranty claims and remediation costs in excess of amounts normally reserved for such items could adversely affect our results of operations and financial condition.

● We are subject to risks associated with energy markets.

● Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, financial condition, results of operations and prospects.

● We may experience fluctuations in revenues and expenses related to our electric operations, which may cause our financial results to fluctuate and could impair our ability to make distributions to our shareholders or scheduled payments on our debt obligations, or to meet covenants under our borrowing agreements.

● Actions by the regulators of our electric operations could result in rate reductions, lower revenues and earnings or delays in recovering capital expenditures.

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● OTP’s operations are subject to an extensive legal and regulatory framework under federal and state laws as well as regulations imposed by other organizations that may have a negative impact on our business and results of operations.

● OTP’s electric transmission and generation facilities could be vulnerable to cyber and physical attack that could impair its ability to provide electrical service to its customers or disrupt the U.S. bulk power system.

● OTP’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs.

● Changes to regulation of generating plant emissions, including but not limited to carbon dioxide emissions, could affect our operating costs and the costs of supplying electricity to our customers.

● Competition from foreign and domestic manufacturers, the price and availability of raw materials, prices and supply of scrap or recyclable material and general economic conditions could affect the revenues and earnings of our manufacturing businesses.

● Our plastics operations are highly dependent on a limited number of vendors for PVC resin and a limited supply of resin. The loss of a key vendor, or any interruption or delay in the supply of PVC resin, could result in reduced sales or increased costs for this segment.

● We compete against a large number of other manufacturers of PVC pipe and manufacturers of alternative products. Customers may not distinguish the pipe companies’ products from those of our competitors.

● Changes in PVC resin prices can negatively affect our plastics business.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

At September 30, 2017we had exposure to market risk associated with interest rates because we had $1.4 million outstanding subject to a variable interest rate that is indexed to LIBOR plus 1.75% under the Otter Tail Corporation Credit Agreement. OTP had$102.2 million in short-term debt outstanding on September 30, 2017 subject to variable interest rates indexed to LIBOR plus 1.25% under the OTP Credit Agreement.

All of our remaining consolidated long-term debt outstanding on September 30, 2017 has fixed interest rates. We manage our interest rate risk through the issuance of fixed-rate debt with varying maturities, through economic refunding of debt through optional refundings, limiting the amount of variable interest rate debt, and the utilization of short-term borrowings to allow flexibility in the timing and placement of long-term debt.

We have not used interest rate swaps to manage net exposure to interest rate changes related to our portfolio of borrowings. We maintain a ratio of fixed-rate debt to total debt within a certain range. It is our policy to enter into interest rate transactions and other financial instruments only to the extent considered necessary to meet our stated objectives. We do not enter into interest rate transactions for speculative or trading purposes.

The companies in our Manufacturing segment are exposed to market risk related to changes in commodity prices for steel, aluminum and polystyrene (PS) and other plastics resins. The price and availability of these raw materials could affect the revenues and earnings of our Manufacturing segment.

The plastics companies are exposed to market risk related to changes in commodity prices for PVC resins, the raw material used to manufacture PVC pipe. The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, sales volume has been higher and when resin prices are falling, sales volume has been lower. Operating income may decline when the supply of PVC pipe increases faster than demand. Due to the commodity nature of PVC resin and the dynamic supply and demand factors worldwide, it is very difficult to predict gross margin percentages or to assume that historical trends will continue.

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Item 4. Controls and Procedures

Under the supervision and with the participation of company management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of September 30, 2017, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2017.

During the fiscal quarter ended September 30, 2017, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are subject of various pending or threatened legal actions and proceedings in the ordinary course of our business. Such matters are subject to many uncertainties and to outcomes that are not predictable with assurance. We record a liability in our consolidated financial statements for costs related to claims, including future legal costs, settlements and judgments, where we have assessed that a loss is probable and an amount can be reasonably estimated. We believe the final resolution of currently pending or threatened legal actions and proceedings, either individually or in the aggregate, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows, excluding any liability for RSG charges described in Note 9 to our consolidated financial statements for which an estimate cannot be made at this time.

Item 1A. Risk Factors

There has been no material change in the risk factors set forth under Part I, Item 1A, “Risk Factors” on pages 26 through 33 of our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 6.      Exhibits

4.1 Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2017, among Otter Tail Corporation, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, and Bank of the West as a Bank (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Otter Tail Corporation on November 2, 2017).

4.2 Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 31, 2017, among Otter Tail Power Company, U.S. Bank National Association, as Administrative Agent and as a Bank, Bank of America, N.A. and JPMorgan Chase Bank, N.A., each as a Co-Syndication Agent and as a Bank, KeyBank National Association, as Documentation Agent and as a Bank, CoBank, ACB, as a Co-Documentation Agent and as a Bank, and Wells Fargo Bank, National Association as a Bank (incorporated by reference to Exhibit 4.2 to the Form 8-K filed by Otter Tail Corporation on November 2, 2017).

31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101 Financial statements from the Quarterly Report on Form 10-Q of Otter Tail Corporation for the quarter ended September 30, 2017, formatted in Extensible Business Reporting Language: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Cash Flows and (v) the Condensed Notes to Consolidated Financial Statements.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

OTTER TAIL CORPORATION

By:    /s/ Kevin G. Moug            

Kevin G. Moug
      Chief Financial Officer and Senior Vice President
   (Chief Financial Officer/Authorized Officer)

Dated: November 8, 2017

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EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles S. MacFarlane, certify that:

1.       I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.       Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.       Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.       The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)     designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)     designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)     evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)     disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.       The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)     all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)     any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2017

/s/ Charles S. MacFarlane
Charles S. MacFarlane

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Moug, certify that:

1.       I have reviewed this Quarterly Report on Form 10-Q of Otter Tail Corporation;

2.       Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.       Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.       The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)     designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)     designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)     evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)     disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.       The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)     all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)     any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2017

/s/ Kevin G. Moug
Kevin G. Moug

Chief Financial Officer and Senior Vice President

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles S. MacFarlane, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles S. MacFarlane

Charles S. MacFarlane

President and Chief Executive Officer 

November 8, 2017

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Otter Tail Corporation (the “Company”) on Form 10-Q for the period ended September 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kevin G. Moug, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Kevin G. Moug

Kevin G. Moug

Chief Financial Officer and Senior Vice President 

November 8, 2017

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 31, 2017
Document Information [Line Items]
Entity Registrant Name	Otter Tail Corp
Entity Central Index Key	0001466593
Trading Symbol	ottr
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Common Stock, Shares Outstanding (in shares)		39,557,491
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Amendment Flag	false

XML

Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents	$ 826
Accounts Receivable:
Trade—Net	87,510	68,242
Other	7,704	5,850
Inventories	78,915	83,740
Unbilled Revenues	14,948	20,080
Income Taxes Receivable		662
Regulatory Assets	21,582	21,297
Other	16,715	8,144
Total Current Assets	228,200	208,015
Investments	8,599	8,417
Other Assets	34,992	34,104
Goodwill	37,572	37,572
Other Intangibles—Net	14,097	14,958
Regulatory Assets	122,670	132,094
Plant
Electric Plant in Service	1,953,375	1,860,357
Nonelectric Operations	214,159	211,826
Construction Work in Progress	138,900	153,261
Total Gross Plant	2,306,434	2,225,444
Less Accumulated Depreciation and Amortization	785,667	748,219
Net Plant	1,520,767	1,477,225
Total Assets	1,966,897	1,912,385
Current Liabilities
Short-Term Debt	103,637	42,883
Current Maturities of Long-Term Debt	197	33,201
Accounts Payable	96,217	89,350
Accrued Salaries and Wages	17,596	17,497
Accrued Taxes	13,277	16,000
Other Accrued Liabilities	14,400	15,377
Liabilities of Discontinued Operations	852	1,363
Total Current Liabilities	246,176	215,671
Pensions Benefit Liability	98,632	97,627
Other Postretirement Benefits Liability	63,215	62,571
Other Noncurrent Liabilities	22,921	21,706
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	242,568	226,591
Deferred Tax Credits	21,747	22,849
Regulatory Liabilities	84,281	82,433
Other	4,432	7,492
Total Deferred Credits	353,028	339,365
Capitalization
Long-Term Debt—Net	490,406	505,341
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2017—39,557,491 Shares; 2016—39,348,136 Shares	197,787	196,741
Premium on Common Shares	342,573	337,684
Retained Earnings	155,618	139,479
Accumulated Other Comprehensive Loss	(3,459)	(3,800)
Total Common Equity	692,519	670,104
Total Capitalization	1,182,925	1,175,445
Total Liabilities and Equity	1,966,897	1,912,385
Cumulative Preferred Shares [Member]
Capitalization
Cumulative Shares
Cumulative Preference Shares [Member]
Capitalization
Cumulative Shares

XML

Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
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)	39,557,491	39,348,136
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

XML

Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues
Electric	$ 103,394	$ 102,712	$ 324,168	$ 313,615
Product Sales	113,063	94,463	318,492	293,284
Total Operating Revenues	216,457	197,175	642,660	606,899
Operating Expenses
Production Fuel – Electric	16,096	14,789	44,955	40,479
Purchased Power – Electric System Use	13,371	11,473	48,935	43,486
Electric Operation and Maintenance Expenses	36,570	36,207	112,799	115,206
Cost of Products Sold (depreciation included below)	86,230	75,405	245,520	228,993
Other Nonelectric Expenses	10,933	10,197	31,535	30,890
Depreciation and Amortization	17,927	18,314	53,689	55,128
Property Taxes – Electric	3,721	3,506	11,228	10,774
Total Operating Expenses	184,848	169,891	548,661	524,956
Operating Income	31,609	27,284	93,999	81,943
Interest Charges	7,393	8,026	22,382	23,996
Other Income	592	499	1,697	2,431
Income Before Income Taxes—Continuing Operations	24,808	19,757	73,314	60,378
Income Tax Expense—Continuing Operations	7,035	5,163	19,295	15,738
Net Income from Continuing Operations	17,773	14,594	54,019	44,640
Discontinued Operations
(Loss) Income – net of Income Tax (Benefit) Expense of ($25), $14, $53 and $114 for the respective periods	(39)	22	78	171
Net Income	$ 17,734	$ 14,616	$ 54,097	$ 44,811
Average Number of Common Shares Outstanding—Basic (in shares)	39,507,581	38,832,659	39,440,416	38,316,324
Average Number of Common Shares Outstanding—Diluted (in shares)	39,795,366	39,005,706	39,712,862	38,457,401
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 0.45	$ 0.38	$ 1.37	$ 1.17
Discontinued Operations (in dollars per share)
(in dollars per share)	0.45	0.38	1.37	1.17
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	0.45	0.37	1.36	1.16
Discontinued Operations (in dollars per share)				0.01
(in dollars per share)	0.45	0.37	1.36	1.17
Dividends Declared Per Common Share (in dollars per share)	$ 0.32	$ 0.3125	$ 0.96	$ 0.9375

XML

Consolidated Statements of Income (Unaudited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Expense - Discontinued Operations	$ (25)	$ 14	$ 53	$ 114

XML

Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net Income	$ 17,734	$ 14,616	$ 54,097	$ 44,811
Unrealized Gain on Available-for-Sale Securities:
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period	(1)	(3)	(2)	(3)
Gains (Losses) Arising During Period	52	(35)	90	65
Income Tax (Expense) Benefit	(18)	13	(31)	(22)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax	33	(25)	57	40
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	157	161	473	470
Income Tax Expense	(63)	(64)	(189)	(188)
Pension and Postretirement Benefit Plans – net-of-tax	94	97	284	282
Total Other Comprehensive Income	127	72	341	322
Total Comprehensive Income	$ 17,861	$ 14,688	$ 54,438	$ 45,133

XML

Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash Flows from Operating Activities
Net Income	$ 54,097	$ 44,811
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations	(78)	(171)
Depreciation and Amortization	53,689	55,128
Deferred Tax Credits	(1,102)	(1,242)
Deferred Income Taxes	15,680	14,924
Change in Deferred Debits and Other Assets	7,875	5,595
Discretionary Contribution to Pension Plan		(10,000)
Change in Noncurrent Liabilities and Deferred Credits	1,788	5,999
Allowance for Equity/Other Funds Used During Construction	(636)	(605)
Stock Compensation Expense—Equity Awards	2,765	1,151
Other—Net	99	(73)
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(21,122)	(3,490)
Change in Inventories	4,825	4,766
Change in Other Current Assets	3,079	1,690
Change in Payables and Other Current Liabilities	(5,153)	(5,945)
Change in Interest and Income Taxes Receivable/Payable	(1,595)	2,538
Net Cash Provided by Continuing Operations	114,211	115,076
Net Cash Used in Discontinued Operations	(134)	(333)
Net Cash Provided by Operating Activities	114,077	114,743
Cash Flows from Investing Activities
Capital Expenditures	(94,549)	(125,913)
Net Proceeds from Disposal of Noncurrent Assets	2,456	4,167
Final Purchase Price Adjustment – BTD-Georgia Acquisition		1,500
Cash Used for Investments and Other Assets	(3,158)	(3,161)
Net Cash Used in Investing Activities	(95,251)	(123,407)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	4,826	(841)
Net Short-Term Borrowings (Repayments)	60,754	(43,499)
Proceeds from Issuance of Common Stock – net of Issuance Expenses	4,349	39,378
Payments for Retirement of Capital Stock	(1,799)	(104)
Proceeds from Issuance of Long-Term Debt		50,000
Short-Term and Long-Term Debt Issuance Expenses		(157)
Payments for Retirement of Long-Term Debt	(48,172)	(161)
Dividends Paid	(37,958)	(35,952)
Net Cash (Used in) Provided by Financing Activities	(18,000)	8,664
Net Change in Cash and Cash Equivalents	826
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period	$ 826

XML

Note 1 - Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Significant Accounting Policies and New Accounting Pronouncements [Text Block]

1.

Summary of Significant Accounting Policies

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable

and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company

’s operating companies recognizing revenue on certain products when shipped, those operating companies have

no

further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does

not

offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

Fair Value Measurements

The Company follows

Accounting Standards Codification (ASC) Topic

820,

Fair Value Measurements and Disclosures

(ASC

820

), for recurring fair value measurements. ASC

820

provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The

three

levels defined by the hierarchy and examples of each level are as follows:

Level

1

– Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level

1

are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

Level

2

– Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level

2

are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level

3

– Significant inputs to pricing have little or

no

observability as of the reporting date. The types of assets and liabilities included in Level

3

are those with inputs requiring significant management judgment or estimation and

may

include complex and subjective models and forecasts.

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, 2017

and

December 31, 2016:

September 30 , 201 7 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,275
Corporate Debt Securities – Held by Captive Insurance Company			$	5,039
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,099
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		714
Total Assets	$	1,989	$	7,138

December 31, 201 6 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,280
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,945
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	849
Total Assets	$	849	$	8,225

The valuation techniques and inputs used for the Level

2

fair value measurements in the table above are as follows:

Government-Backed and Government-Sponsored Enterprises

’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company

– Fair values are determined on the basis of valuations provided by a

third

-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service

may

be based on broker quotes.

Coyote Station Lignite Supply Agreement

– Variable Interest Entity

—In

October 2012

the Coyote Station owners, including Otter Tail Power Company (OTP), entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in

May 2016

and ending in

December 2040.

The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from

May 2016

through

December 2040

and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements.

No

single owner of Coyote Station owns a majority interest in Coyote Station and

none,

individually, has the power to direct the activities that most significantly impact CCMC. Therefore,

none

of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is

not

required to include CCMC in its consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the production period terminates prior to

December 31, 2040

and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC

’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of

September 30, 2017

could be as high as

$58.0

 million, OTP’s

35%

share of unrecovered costs.

Inventories

Inventories

, valued at the lower of cost or net realizable value, consist of the following:

	September 30,		December 31,
(in thousands)	201 7		201 6
Finished Goods	$	19,500	$	27,755
Work in Process		13,885		11,754
Raw Material, Fuel and Supplies		45,530		44,231
Total Inventories	$	78,915	$	83,740

Goodwill and Other Intangible Assets

An assessment of the carrying amounts of goodwill of the Company

’s operating units as of

December 31, 2016

indicated the fair values are substantially in excess of their respective book values and

not

impaired.

The following table

indicates there were

no

changes to goodwill by business segment during the

first

nine

months of

2017:

(in thousands)	Gross Balance December 31, 2016		Accumulated Impairments		Balance (net of impairments) December 31, 2016		Adjustments to Goodwill in 201 7		Balance (net of impairments) September 30, 2017
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, 2017

and

December 

31,

 

2016:

September 30 , 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,710	$	13,781	27	-	215
Covenant not to Compete		590		410		180		11
Other		140		4		136		35
Total	$	23,221	$	9,124	$	14,097
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36	-	224
Covenant not to Compete		590		262		328		20
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	201 7		201 6		201 7		201 6
Amortization Expense – Intangible Assets	$	336	$	348	$	1,001	$	1,103

The estimated annual amortization expense for these intangible assets for the next

five

years is:

(in thousands)	2017		2018		2019		2020		2021
Estimated Amortization Expense – Intangible Assets	$	1,346	$	1,313	$	1,181	$	1,131	$	1,099

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	201 7		201 6
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	17,940	$	11,552

New Accounting Standards

Adopted

Accounting Standards Update (

ASU

)

2015

-

11

—In

July 2015

the Financial Accounting Standards Board (FASB) issued ASU

No.

2015

-

11,

Inventory (Topic

330

): Simplifying the Measurement of Inventory,

which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update was effective prospectively for fiscal years and interim periods beginning after

December 15, 2016.

The Company adopted the updates in ASU

2015

-

11

in the

first

quarter of

2017.

The adoption of the updated standard did

not

have a material impact on the Company’s consolidated financial statements as market and net realizable value were substantially the same for the inventories of its manufacturing companies.

New Accounting Standards

Pending

Adopt

ion

ASU

2014

-

09

—In

May 2014

the FASB issued ASU

No.

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

(ASC

606

). ASC

606

is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC

606

also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

Amendments to the ASC in ASU

2014

-

09,

as amended, are effective for fiscal years beginning after

December 15, 2017.

Early adoption is permitted, but

not

any earlier than

January 1, 2017.

Application methods permitted are: (

1

) full retrospective, (

2

) retrospective using

one

or more practical expedients and (

3

) retrospective with the cumulative effect of initial application recognized at the date of initial

application. The Company does

not

plan to adopt the updated guidance prior to

January 1, 2018.

As of

September 30, 2017

the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU

2014

-

09

will be applicable and is developing controls for new processes that will be required to track and report revenues where the timing of revenue recognition will change under ASU

2014

-

09.

Based on review of the Company’s revenue streams, the Company does

not

anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU

2014

-

09.

The Company will adopt the updates in ASU

2014

-

09

on a modified retrospective basis with the cumulative effect of initial application on retained earnings and other balance sheet accounts, if any, recognized on

January 1, 2018,

the date of initial application. Adoption of ASU

2014

-

09

will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that

may

be required to be reported under the updated standard.

ASU

2016

-

02

—In

February 2016

the FASB issued ASU

No.

2016

-

02,

Leases (Topic

842

)

(ASU

2016

-

02

). ASU

2016

-

02

is a comprehensive amendment of the ASC, creating Topic

842,

which will supersede the current requirements under ASC Topic

840

on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic

842

affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic

842

is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic

842

retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic

842

also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU

2016

-

02

are effective for fiscal years beginning after

December 15, 2018,

including interim periods within those fiscal years. Early application of the amendments in ASU

2016

-

02

is permitted. The Company is currently reviewing ASU

2016

-

02,

has developed a list of all current leases outstanding and is identifying key impacts to its businesses to determine areas where the amendments in ASU

2016

-

02

will be applicable and is evaluating transition options. The Company does

not

currently plan to apply the amendments in ASU 

2016

-

02

to its consolidated financial statements prior to

2019.

ASU

2017

-

04

—In

January 2017

the FASB issued ASU

No.

2017

-

04,

Intangibles—Goodwill and Other (Topic

350

): Simplifying the Test for Goodwill Impairment

(ASU

2017

-

04

), which

simplifies how an entity is required to test goodwill for impairment by eliminating Step

2

from the goodwill impairment test. Step

2

measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill.

In computing the implied fair value of goodwill under Step

2,

an entity had to perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination.

Under the amendments in ASU

2017

-

04,

an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will

not

exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in

ASU

2017

-

04

modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity

no

longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step

2

from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU

2017

-

04

are effective for annual or any interim goodwill impairment tests in fiscal years beginning after

December 15, 2019.

Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after

January 1, 2017.

ASU

2017

-

07

—In

March 2017

the FASB issued ASU

No.

2017

-

07,

Compensation—Retirement Benefits (Topic

715

): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

(ASU

2017

-

07

), which

is intended

to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost.

ASC

Topic

715,

Compensation—Retirement Benefits

(ASC

715

)

,

does

not

prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does

not

require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets.

The amendments in ASU

2017

-

07

require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost as defined in ASC

715

are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in ASU

2017

-

07

also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU

2017

-

07

are effective for annual periods beginning after

December 15, 2017,

including interim periods within those annual periods. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets.

The majority of the Company

’s benefit costs to which the amendments in ASU

2017

-

07

apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU

2017

-

07

deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU

2017

-

07

may

have on its consolidated financial statements, financial position and results of operations and is determining the adjustments and regulatory assets to be established in order to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under the ASU

2017

-

07

amendments to GAAP. The non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on the Company’s consolidated income statements upon adoption of the amendments in ASU

2017

-

07.

T

he Company’s non-service costs components of net periodic post-retirement benefit costs that will be capitalized to plant in service in

2017

but that would be recorded as regulatory assets if the amendments in ASU

2017

-

07

were applicable in

2017

are expected to be

$0.7

million. The Company’s non-service costs components of net periodic post-retirement benefit costs included in operating expense in

2017

that would be included in other income and deductions under ASU

2017

-

07

are expected to be

$5.7

million. The Company does

not

plan to adopt the updates in ASU 

2017

-

07

prior to the

first

quarter of

2018,

the required effective period for application of the updates by the Company.

XML

Note 2 - Segment Information

9 Months Ended

Sep. 30, 2017

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

– Summary of Significant Accounting Policies. The Company's businesses have been classified into

three

segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers.

These businesses sell products and provide services to customers primarily in the United States. The Company’s business structure currently includes the following

three

segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.

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 polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.

OTP is a wholly owned subsidiary of the Company. All of the Company

’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is

not

an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.

No

single customer accounted for over

10%

of the Company

’s consolidated revenues in

2016.

All of the Company’s long-lived assets are within the United States and sales within the United States accounted for

97.9%

and

98.5%

of its operating revenues for the respective

three

-month periods ended

September 30, 2017

and

2016,

and

98.2%

and

98.6%

of its operating revenues for the respective

nine

-month periods ended

September 30, 2017

and

2016.

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

- and

nine

-month periods ended

September 30, 2017

and

2016

and total assets by business segment as of

September 30, 2017

and

December 

31,

2016

are presented in the following tables:

Operating Revenue

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	103,399		$	102,723		$	324,186		$	313,642
Manufacturing		54,355			52,171			172,076			170,443
Plastics		58,708			42,292			146,416			122,841
Intersegment Eliminations		(5	)		(11	)		(18	)		(27	)
Total	$	216,457		$	197,175		$	642,660		$	606,899

Interest Charges

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	201 7		201 6		201 7		201 6
Electric	$	6,362	$	6,304	$	19,187	$	18,744
Manufacturing		555		974		1,662		2,972
Plastics		157		273		483		796
Corporate and Intersegment Eliminations		319		475		1,050		1,484
Total	$	7,393	$	8,026	$	22,382	$	23,996

Income Taxes

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	3,548		$	4,730		$	12,052		$	11,262
Manufacturing		676			182			3,304			2,992
Plastics		3,826			1,577			8,074			5,206
Corporate		(1,015	)		(1,326	)		(4,135	)		(3,722	)
Total	$	7,035		$	5,163		$	19,295		$	15,738

Net Income (Loss)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	10,869		$	12,513		$	36,563		$	34,199
Manufacturing		1,608			1,246			6,735			6,108
Plastics		6,092			2,346			13,166			7,983
Corporate		(796	)		(1,511	)		(2,445	)		(3,650	)
Discontinued Operations		(39	)		22			78			171
Total	$	17,734		$	14,616		$	54,097		$	44,811

Identifiable

Assets

	September 30,		December 31,
(in thousands)	201 7		201 6
Electric	$	1,660,591	$	1,622,231
Manufacturing		167,004		166,525
Plastics		98,283		84,592
Corporate		41,019		39,037
Total	$	1,966,897	$	1,912,385

XML

Note 3 - Rate and Regulatory Matters

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Public Utilities Disclosure [Text Block]

3.

Rate and Regulatory Matters

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 Federal Energy Regulatory Commission (FERC) impacting OTP’s revenues in

2017

and

2016.

Major Capital Expenditure Projects

Big Stone South

–Brookings

Multi-Value Transmission Project (

MVP

)

and

Capacity Expansion

2020

(

CapX2020

)

Project

—This

345

kiloVolt (kV) transmission line extends approximately

70

miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in

December 2011.

MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the

third

quarter of

2015

and the line was energized on

September 8, 2017.

OTP’s capitalized costs on this project as of

September 30, 2017

were approximately

$70.0

 million, which includes assets that are

100%

owned by OTP.

Big Stone South

–Ellendale MVP

—This is a

345

kV transmission line that will extend

163

miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in

December 2011.

Construction began on this line in the

second

quarter of

2016

and is expected to be completed in

2019.

OTP’s capitalized costs on this project as of

September 30, 2017

were approximately

$78.4

million, which includes assets that are

100%

owned by OTP.

Recovery of OTP

’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.

Minnesota

2016

General Rate Case

—The MPUC rendered its final decision in OTP’s

2016

general rate case in

March 2017

and issued its written order on

May 1, 2017.

Pursuant to the order, OTP’s allowed rate of return on rate base will decrease from

8.61%

to

7.5056%

and its allowed rate of return on equity will decrease from

10.74%

to

9.41%.

On

July 6, 2017

the MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case and confirmed details of its

May 1, 2017

order approving OTP’s request for a revenue increase in Minnesota.

The MPUC

’s order also included: (

1

) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South-Brookings and Big Stone South-Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (

2

) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (ECR) and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.

Information on

interim and final rate increases and interim revenue refund accrued is detailed in the tables below:

($ in thousands)	Interim Rates Authorized April 14, 2016			Final Rates
Revenue Increase – Annualized based on Test Year Data	$	16,816		$	12,100
Revenue Percent Increase		9.56	%		6.23	%
Return on Rate Base		8.07	%		7.5056	%
Jurisdictional Rate Base based on Test Year Data	$	483,000		$	471,000
Return on Equity		10.1	%		9.41	%
Based on Equity to Total Capital of		52.50	%		52.50	%
Debt to Total Capital		47.50	%		47.50	%

Interim Revenue (in thousands)	April 16, 2016 through September 30, 2017
Billed		$	21,847
Accrued Refund		$	8,237
Net Interim Revenue		$	13,610
Interest on Refundable Amount		$	233
Refund Liability as of September 30, 2017		$	8,470

In addition to the interim rate refund, OTP will be required to refund the difference

between (

1

) amounts collected under its Minnesota

ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (

2

) amounts that would have been collected based on the lower

9.41%

ROE approved in its

2016

general rate case going back to

April 16, 2016,

the date interim rates were implemented. As of

September 30, 2017

the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were

$0.9

million and

$1.4

 million, respectively. These amounts will be refunded to Minnesota customers over a

12

-month period through reductions in the Minnesota ECR and TCR rider rates that take effect

November 1, 2017,

as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.

OTP will continue to accrue the interim

and rider rate refunds until final rates become effective, for bills rendered on and after

November 1, 2017.

The interim rate refund, including interest, will be applied as a credit to Minnesota customers’ electric bills beginning

November 17, 2017.

Minnesota Conservation Improvement Programs

(MNCIP)

—OTP recovers conservation related costs

not

included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On

May 25, 2016

the MPUC adopted the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The new model provides utilities an incentive of

13.5%

of

2017

net benefits,

12%

of

2018

net benefits and

10%

of

2019

net benefits, assuming the utility achieves

1.7%

savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately

50%

compared to the previous incentive mechanism. MNCIP incentives include

$5.0

million approved for

2016,

$4.3

million approved for

2015

and

$3.0

million approved for

2014.

Transmission Cost Recovery Rider

—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC

may

approve annual rate adjustments filed pursuant to the rate schedule.

In OTP

’s

2016

general rate case order issued on

May 1, 2017,

the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the Commission’s Order diverts interstate wholesale revenues that have been approved by FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. On

August 18, 2017

OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals

to contest the portion of the order requiring OTP to allocate costs between jurisdictions of the FERC MVP transmission projects in the TCR rider. OTP believes the MPUC-ordered treatment conflicts with federal authority over transmission of electricity in interstate commerce and rates for the transmission of electricity subject to the jurisdiction of the FERC as set forth in the Federal Power Act of

1935,

as amended (Federal Power Act).

Environmental Cost Recovery Rider

—OTP has an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provides for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s

2010

general rate case. In OTP’s

2016

general rate case, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, with the transition occurring when final rates are implemented.

North Dakota

General Rates

—

O

n

November 2, 2017

OTP filed a request with the NDPSC for a rate review and an increase in annual revenues from non-fuel base rates of

$13.1

 million or an

8.7%.

In the request, OTP proposed an allowed return on rate base of

7.97%

and an allowed rate of return on equity of

10.30%.

Pursuant to the request, an interim rate increase is expected to go into effect on

January 1, 2018.

OTP

’s most recent general rate increase in North Dakota of

$3.6

million, or approximately

3.0%,

was granted by the NDPSC in an order issued on

November 25, 2009

and effective

December 2009.

Pursuant to the order, OTP’s allowed rate of return on rate base was set at

8.62%,

and its allowed rate of return on equity was set at

10.75%.

Renewable Resource Adjustment

—OTP has a North Dakota Renewable Resource Adjustment which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.

Transmission Cost Recovery Rider

—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case.

Environmental Cost Recovery Rider

—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS

and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects. The ECR rider provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case.

South Dakota

2010

General Rate Case

—OTP’s most recent general rate increase in South Dakota of approximately

$643,000

or approximately

2.32%

was granted by the SDPUC in an order issued on

April 21, 2011

and effective with bills rendered on and after

June 1, 2011.

Pursuant to the order, OTP’s allowed rate of return on rate base was set at

8.50%.

Transmission Cost Recovery Rider

—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities.

Environmental Cost Recovery Rider

—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.

Rate

Rider Updates

The following table provides summary information on the status of updates

since

January 1, 2015

for the rate riders described above:

Rate Rider	R - Request Date A - Approval Date	Effective Date Requested or Approved	Annual Revenue ($000s)			Rate
Minnesota
Conservation Improvement Program
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 201 7	$	9,868		$0.00 536/kwh
2015 Incentive and Cost Recovery	A – July 19, 2016	October 1, 2016	$	8,590		$0.00275/kwh
2014 Incentive and Cost Recovery	A – July 10, 2015	October 1, 2015	$	8,689		$0.00287/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
2014 Annual Update	A – February 18, 2015	March 1, 2015	$	8,388		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	- 0.935% of Rev
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of Rev
2015 Annual Update	A – March 9, 2016	October 1, 2015	$	12,104		7.006% of Rev
North Dakota
Renewable Resource Adjustment
201 6 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.00 5% of Rev
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7. 573% of Rev
201 4 Annual Update	A – March 25, 2015	April 1, 2015	$	5,441		4.069% of Rev
Transmission Cost Recovery
201 7 Annual Update	R – August 31, 2017	January 1, 2018	$	8,593		Various
201 6 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
2015 Annual Update	A – December 16, 2015	January 1, 2016	$	9,985		Various
Environmental Cost Recovery
201 7 Annual Update	A – July 12, 2017	August 1, 2017	$	9,917		7.633% of base
201 6 Annual Update	A – June 22, 2016	July 1, 2016	$	10,359		7. 904% of base
2015 Annual Update	A – June 17, 2015	July 1, 2015	$	12,249		9.193 % of base
South Dakota
Transmission Cost Recovery
201 6 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
2014 Annual Update	A – February 13, 2015	March 1, 2015	$	1,538		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00 483/kwh
201 6 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh
201 5 Annual Update	A – October 15, 2015	November 1, 2015	$	2,728		$0.00643/kwh

1

Approved on a provisional basis

in the Minnesota general rate case docket

and subject to

revision

in a separate docket

.

The following table presents revenue recorded by OTP under

rate riders in place in Minnesota, North Dakota and South Dakota:

Revenues Recorded under Rider Rates	Three Months Ended September 30,					Nine Months Ended September 30,
Rate Rider (in thousands)	2017			2016		2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,499		$	2,839	$	6,567	$	7,554
Transmission Cost Recovery		(594	)		779		2,849		4,188
Environmental Cost Recovery		1,669			3,127		7,305		9,362
North Dakota
Renewable Resource Adjustment		2,213			2,170		5,822		6,151
Transmission Cost Recovery		2,410			1,950		6,305		6,155
Environmental Cost Recovery		2,396			2,762		7,272		8,344
South Dakota
Transmission Cost Recovery		596			335		1,324		1,397
Environmental Cost Recovery		613			691		1,755		1,951
Conservation Improvement Program Costs and Incentives		104			135		520		418

1

Includes MNCIP costs recovered in base rates.

FERC

Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a

one

day suspension period, subject to ultimate approval by the FERC.

Multi-Value Transmission Projects

—On

December 16, 2010

the FERC approved the cost allocation for a new classification of projects in the MISO region called 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

a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP,

may

collect under the MISO Tariff. The complainants sought to reduce the

12.38%

ROE used in MISO

’s transmission rates to a proposed

9.15%.

The complaint established a

15

-month refund period from

November 12, 2013

to

February 11, 2015.

A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on

December 22, 2015

finding that the MISO transmission owners’ ROE should be

10.32%,

and the FERC issued an order on

September 28, 2016

setting the base ROE at

10.32%

.

A number of parties requested rehearing of the

September 2016

order and the requests are pending FERC action.

On

November 6, 2014

a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional

50

-basis points for Regional Transmission Organization participation (RTO Adder). On

January 5, 2015

the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the

November 12, 2013

complaint and OTP

’s incentive rate filing, OTP’s ROE will be

10.82%

(a

10.32%

base ROE plus the

0.5%

RTO Adder) effective

September 28, 2016.

On

February 12, 2015

another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP,

may

collect under the MISO Tariff from

12.38%

to a proposed

8.67%.

This

second

complaint established a

second

15

-month refund period from

February 12, 2015

to

May 11, 2016.

The FERC issued an order on

June 18, 2015

setting the complaint for hearings before an ALJ, which were held the week of

February 16, 2016.

A non-binding decision by the presiding ALJ was issued on

June 30, 2016

finding that the MISO transmission owners

’ ROE should be

9.7%.

OTP is currently waiting for the issuance of a FERC order on the

second

complaint.

Based on

the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a

$2.7

million liability on its balance sheet as of

December 31, 2016,

representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC ordered reduction in the MISO tariff allowed ROE for the

first

15

-month refund period in its

February

and

June 2017

billings. The refund, in combination with a decision in the

2016

Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from

$2.7

million on

December 

31,

2016

to

$1.6

million as of

September 30, 2017.

In

June 2014,

the FERC adopted a

two

-step ROE methodology for electric utilities in an order issued in a complaint

proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the

two

ROE complaints involving MISO transmission owners discussed above. In

April 2017

the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s

June 2014

ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had

not

properly determined that the ROE authorized for NETOs prior to

June 2014

was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the

April 2017

action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required.

On

September 29, 2017

the MISO transmission owners filed a motion to dismiss the

second

complaint based on the D.C. Circuit decision in the NETO complaint. If FERC grants the motion to dismiss, it would eliminate the refund obligation from the

second

complaint and the ROE from the

first

complaint would remain in effect.

XML

Note 4 - Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Schedule of Regulatory Assets and Liabilities [Text Block]

4.

Regulatory Assets and Liabilities

As a regulated

entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic

980,

Regulated Operations

(ASC

980

). This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC

980

-

605

-

25

provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:

	September 30, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	6,444	$	103,434	$	109,878	see below
Conservation Improvement Program Costs and Incentives 2		8,230		2,351		10,581		24
Deferred Marked-to-Market Losses 1		4,063		3,420		7,483		39
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,525		6,525	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2		88		2,432		2,520		27
Big Stone II Unrecovered Project Costs – Minnesota 1		658		1,597		2,255		43
Debt Reacquisition Premiums 1		252		1,026		1,278		180
Recoverable Fuel and Purchased Power Costs 1		885		--		885		12
Deferred Income Taxes 1		--		833		833	asset lives
North Dakota Renewable Resource Rider Accrued Revenues 2		189		585		774		18
Big Stone II Unrecovered Project Costs – South Dakota 2		100		467		567		68
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		496		--		496		7
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		142		--		142		3
South Dakota Transmission Cost Recovery Rider Accrued Revenues 2		35		--		35		3
Total Regulatory Assets	$	21,582	$	122,670	$	144,252
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	82,485	$	82,485	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		1,808		616		2,424		24
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,722		--		1,722		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		716		342		1,058		15
Deferred Income Taxes		--		720		720	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		385		--		385		7
South Dakota Environmental Cost Recovery Rider Accrued Refund		252		--		252		12
Sout h Dakota Transmission Cost Recovery Rider Accrued Refund		172		--		172		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		99		33		132		15
Other		6		85		91		195
Nort h Dakota Environmental Cost Recovery Rider Accrued Refund		43		--		43		12
Total Regulatory Liabilities	$	5,203	$	84,281	$	89,484
Net Regulatory Asset Position	$	16,379	$	38,389	$	54,768

1

Costs subject to recovery without a rate of return.

2

Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

	December 31, 2016						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	6,443	$	108,267	$	114,710	see below
Conservation Improvement Program Costs and Incentives 2		4,836		5,158		9,994		21
Deferred Marked-to-Market Losses 1		4,063		6,467		10,530		48
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,153		6,153	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2		333		--		333		12
Big Stone II Unrecovered Project Costs – Minnesota 1		778		2,087		2,865		52
Debt Reacquisition Premiums 1		325		1,214		1,539		189
Recoverable Fuel and Purchased Power Costs 1		1,798		--		1,798		12
Deferred Income Taxes 1		--		1,014		1,014	asset lives
North Dakota Renewable Resource Rider Accrued Revenues 2		1,319		482		1,801		15
Big Stone II Unrecovered Project Costs – South Dakota 2		100		543		643		77
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		1,082		--		1,082		12
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		--		568		568		24
South Dakota Transmission Cost Recovery Rider Accrued Revenues 2		73		141		214		14
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		113		--		113		12
Minnesota Renewable Resource Rider Accrued Revenues 2		34		--		34		9
Total Regulatory Assets	$	21,297	$	132,094	$	153,391
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	80,404	$	80,404	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		757		--		757		12
Minnesota Environmental Cost Recovery Rider Accrued Refund		139		--		139		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,381		782		2,163		24
Deferred Income Taxes		--		818		818	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		208		919		16
South Dakota Environmental Cost Recovery Rider Accrued Refund		285		--		285		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		132		132		24
Other		21		89		110		204
Total Regulatory Liabilities	$	3,294	$	82,433	$	85,727
Net Regulatory Asset Position	$	18,003	$	49,661	$	67,664

1

Costs subject to recovery without a rate of return.

2

Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic

715,

Compensation—Retirement Benefits

, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.

Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.

All Deferred Marked-to-Market Losses recorded as of

September 30, 2017

relate to forward purchases of energy scheduled for delivery through

December 2020.

The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.

MISO Schedule

26/26A

Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule

26/26A

for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.

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

18

0

months.

The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic

740,

Income Taxes

.

North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have

not

been billed to North Dakota customers as of

September 30, 2017.

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 Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP

’s

2016

rate case in Minnesota currently being recovered over a

24

-month period beginning with the establishment of interim rates in

April 2016.

The North Dakota Transmission

Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have

not

been billed to North Dakota customers as of

September 30, 2017.

The South Dakota Transmission

Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have

not

been billed to South Dakota customers as of

September 30, 2017.

Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have

not

been billed to Minnesota customers. On

April 4, 2013

the MPUC approved OTP

’s request to set the rider rate to

zero

effective

May 1, 2013

and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an

18

-month period beginning with the establishment of interim rates in

April 2016.

The Accumulated Reserve for Estimated Removal Costs

– Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.

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 are refundable to Minnesota customers as of

September 30, 2017.

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, 2017.

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, 2017.

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 are subject to refund over a

24

-month period beginning with the establishment of interim rates in

April 2016.

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, 2017.

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, 2017.

The

North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of

September 30, 2017.

If for any reason OTP ceases to meet the criteria for application of guidance under ASC

980

for all or part of its operations, the regulatory assets and liabilities that

no

longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC

980

ceases.

XML

Note 5 - Open Contract Positions Subject to Legally Enforceable Netting Arrangements

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Open Contract Positions Subject to Legally Enforceable Netting Arrangements [Text Block]

5.

Open

Contract

Position

s

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 following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of

September 30, 2017

and

December 

31,

2016:

(in thousands)	September 30, 201 7			December 31, 201 6
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	--		$	--
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(13,591	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(13,591	)	$	(17,382	)

The following table provides a breakdown of OTP

’s credit risk standing on forward energy contracts in marked-to-market loss positions as of

September 30, 2017

and

December 31, 2016:

(in thousands)	September 30, 2017		December 31, 2016
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--	$	--
Contracts Requiring Cash Deposits if OTP ’s Credit Falls Below Investment Grade 1		13,591		17,382
Total Loss Contracts based on Current Market Values	$	13,591	$	17,382
1 Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP ’s Credit Falls Below Investment Grade	$	13,591	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		--		--
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	13,591	$	17,382

XML

Note 6 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Stockholders Equity and Earnings per Share [Text Block]

6.

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 Income/(Loss)			Total Common Equity
Balance, December 31, 201 6	$	196,741		$	337,684		$	139,479		$	(3,800	)	$	670,104
Common Stock Issuances, Net of Expenses		1,285			3,684									4,969
Common Stock Retirements		(239	)		(1,560	)								(1,799	)
Net Income								54,097						54,097
Other Comprehensive Income											341			341
Employee Stock Incentive Plan s Expense					2,765									2,765
Common Dividends ($0. 96 per share)								(37,958	)					(37,958	)
Balance, September 30, 2017	$	197,787		$	342,573		$	155,618		$	(3,459	)	$	692,519

Shelf Registration

and Common Share Distribution Agreement

The Company

’s shelf registration statement filed with the Securities and Exchange Commission on

May 11, 2015,

under which the Company

may

offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on

May 11, 2018.

On

May 11, 2015,

the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it

may

offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of

$75

million.

Common Shares

Following is a reconciliation of the Company

’s common shares outstanding from

December 31, 2016

through

September 30, 2017:

Common Shares Outstanding December 31, 201 6	39,348,136
Issuances:
Executive Stock Performance Awards (2014 shares earned)	89,291
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	68,235
Cash Invested	29,463
Vesting of Restricted Stock Units	22,225
Restricted Stock Issued to Directors	17,600
Employee Stock Ownership Plan	14,835
Employee Stock Purchase Plan:
Dividends Reinvested	9,566
Cash Invested	5,284
Directors Deferred Compensation	560
Retirements:
Shares Withheld for Individual Income Tax Requirements	(47,704	)
Common Shares Outstanding September 30, 2017	39,557,491

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the

three

- and

nine

-month periods ended

September 30, 2017

and

2016.

The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and

not

outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:

	Three Months ended September 30				Nine Months ended September 30
	201 7		201 6		201 7		201 6
Weighted Average Common Shares Outstanding – Basic		39,507,581		38,832,659		39,440,416		38,316,324
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		211,996		103,084		195,869		80,450
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		55,975		48,645		54,645		42,620
Nonvested Restricted Shares		16,982		18,029		18,923		14,556
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,832		3,289		3,009		3,451
Total Dilutive Shares		287,785		173,047		272,446		141,077
Weighted Average Common Shares Outstanding – Diluted		39,795,366		39,005,706		39,712,862		38,457,401

The effect of dilutive shares on earnings per share for the

three

- and

nine

-month periods ended

September 30, 2017

and

2016,

resulted in

no

differences greater than

$0.01

between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.

XML

Note 7 - Share-based Payments

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

7.

Share-Based Payments

Stock Incentive Awards

T

he following stock incentive awards were granted under the

2014

Stock Incentive Plan during the

nine

-month period ended

September 30, 2017:

Award	Grant-Date	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Stock Performance Awards Granted to Executive Officers	February 2, 2017		59,500	$	31.00	December 31, 2019
Restricted Stock Units Granted to Executive Officers	February 2, 2017		15,900	$	37.65	25% per year through February 6, 2021
Restricted Stock Units Granted to Key Employees	April 10, 2017		9,995	$	32.78	100% on April 8, 20 21
	September 25, 2017		1,000	$	38.29	100% on April 8, 2021
Restricted Stock Granted to Nonemployee Directors	April 10, 2017		17,600	$	37.75	25% per year through April 8, 20 21

Under the performance share awards

, the aggregate award for performance at target is

59,500

shares. For target performance the participants would earn an aggregate of

39,667

common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of

January 1, 2017

through

December 31, 2019,

with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the

20

trading days immediately following

January 1, 2017

and the average closing price for the

20

trading days immediately preceding

January 1, 2020.

The participants would also earn an aggregate of

19,833

common shares for achieving the target set for the Company’s

3

-year average adjusted ROE. Actual payment

may

range from

zero

to

150%

of the target amount, or up to

89,250

common shares. There are

no

voting or dividend rights related to the performance shares until common shares, if any, are issued at the end of the performance measurement period. The amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event. The vesting of these performance awards is accelerated and paid at target in the event of a change in control, disability or death and on retirement at or after age

62

for certain officers who are parties to executive employment agreements with the Company. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC

718,

and recognized over the grantee’s requisite service period based on the grant-date fair value of the award.

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

share of the Company’s common stock on the date of grant.

The grant-date fair value of each restricted stock unit granted to a key employee that is

not

an executive officer was based on the average of the high and low market price of

one

share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the respective vesting periods.

The restricted shares granted to the Company

’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares

not

vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price of

one

share of the Company’s common stock on the date of grant.

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, 2017

the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately

$4.9

million (before income taxes) which will be amortized over a weighted-average period of

2.2

years.

Amounts of compensation expense recognized under the Company

’s

six

stock-based payment programs for the

three

- and

nine

-month periods ended

September 30, 2017

and

2016

are presented in the table below:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	201 7		201 6		201 7		201 6
Stock Performance Awards Granted to Executive Officers	$	494	$	455	$	1,568	$	1,296
Restricted Stock Units Granted to Executive Officers		104		64		472		373
Restricted Stock Granted to Executive Officers		16		22		54		73
Restricted Stock Granted to Nonemployee Directors		144		128		416		363
Restricted Stock Units Granted to Key Employees		87		62		255		207
Employee Stock Purchase Plan (15% discount)		--		47		--		135
Totals	$	845	$	778	$	2,765	$	2,447

XML

Note 8 - Retained Earnings Restriction

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Retained Earnings Restrictions [Text Block]

8.

Retained Earnings Restriction

The Company is a holding company with

no

significant operations of its own. The primary source of funds for payments of dividends to the Company

’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.

Both the Company and OTP

debt 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

meet certain financial covenants. As of

September 30, 2017

the Company was in compliance with these financial covenants. See note

10

to the Company’s consolidated financial statements on Form

10

-K for the year ended

December 31, 2016

for further information on the covenants.

Under the Federal Power Act, a public utility

may

not

pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (

1

) the source of the dividends is clearly disclosed, (

2

) the dividend is

not

excessive and (

3

) there is

no

self-dealing on the part of corporate officials.

The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity

-to-total-capitalization ratio between

47.4%

and

58.0%

based on OTP’s

2017

capital structure petition approved by order of the MPUC on

September 1, 2017.

As of

September 30, 2017

OTP’s equity-to-total-capitalization ratio including short-term debt was

51.8%

and its net assets restricted from distribution totaled approximately

$462,000,000.

Total capitalization for OTP cannot currently exceed

$1,178,024,000.

XML

Note 9 - Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Commitments and Contingencies Disclosure [Text Block]

9.

Commitments and Contingencies

Construction and Other Purchase Commitments

At

December 31,

201

6

OTP had commitments under contracts extending into

2019,

including its share of construction program commitments, totaling approximately

$84.8

million. At

September 30, 2017

OTP had commitments under contracts extending into

2019

,

including its share of construction program commitments, totaling approximately

$82.6

million.

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

2040

.

OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP

’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of

2019

and

2040,

respectively. In the

first

quarter of

2017

a portion of the coal supply for Big Stone Plant contracted for delivery in

2016

was rolled into

2018

and some additional coal was contracted for delivery in

2018

and

2019.

These arrangements result in an additional commitment for the purchase of coal in

2018

and

2019

totaling approximately

$3.0

million. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through

December 31, 2023.

OTP has

no

fixed minimum purchase requirements under the agreement, but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement.

Operating Leases

OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company

’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.

Contingencies

OTP had a

$2.7

million

refund liability on its balance sheet as of

December 31, 2016

representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. In the

February

and

June 2017

MISO billings, MISO processed the refund of the FERC-ordered reduction in the MISO tariff allowed ROE for the

first

15

-month refund period. The refund, in combination with a decision in the

2016

Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from

$2.7

million as of

December 31, 2016

to

$1.6

million as of

September 30, 2017.

Together with as many as

200

utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market

’s start on

April 1, 2005

until the conclusion of the proceedings on

May 2, 2015.

The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to

not

resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. The D.C. Circuit

has set a briefing schedule with final briefs due in

January 2018.

MISO has

not

made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have a material effect on the Company’s results of operations.

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. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as

$1.0

million, excluding any liability for RSG charges for which an estimate cannot be made at this time.

In

2014

the Environmental Protection Agency (EPA) published

both proposed standards of performance for carbon dioxide (

CO2

) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed

CO2

emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under section

111

of the Clean Air Act. The EPA published final rules for each of these proposals on

October 23, 2015.

Both rules were challenged on legal grounds. On

February 

9,

2016

the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on

September 27, 2016

before the full court, and a decision was expected in the

first

half of

2017.

However, pursuant to Executive Order

13783,

Promoting Energy Independence and Economic Growth

, the EPA was directed to consider suspending, revising or rescinding the

CO2

rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On

October 16, 2017

the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.

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, 2017

will

not

be material.

XML

Note 10 - Short-term and Long-term Borrowings

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Debt Disclosure [Text Block]

10.

Short-Term and Long-Term Borrowings

The following table presents the status of our lines of credit as of

September 30, 2017

and

December 31, 2016:

(in thousands)	Line Limit		In Use on September 30, 2017		Restricted due to Outstanding Letters of Credit		Available on September 30, 2017		Available on December 31, 201 6
Otter Tail Corporation Credit Agreement	$	130,000	$	1,417	$	--	$	128,583	$	130,000
OTP Credit Agreement		170,000		102,220		300		67,480		127,067
Total	$	300,000	$	103,637	$	300	$	196,063	$	257,067

On

October 31, 2017

both credit agreements were amended to extend the expiration dates by

one

year from

October 29, 2021

to

October 31, 2022.

Debt Retirements

On

February 5, 2016

the Company borrowed

$50

million under

a Term Loan Agreement at an interest rate based on the

30

 day

LIBOR

plus

90

basis points.

The Company repaid

$35.0

million of the

$50

million in the

fourth

quarter of

2016

and made additional repayments of

$3.0

million in

January 2017,

$3.0

million in

June 2017

and

$9.0

million on

August 7, 2017.

As of

September 30, 2017

the Company had

no

borrowings under the Term Loan Agreement.

On

August 21, 2017

OTP used borrowings under the OTP

Credit Agreement to retire its

$33

million

5.95%,

Series A Senior Unsecured Notes, which matured on

August 20, 2017.

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, 2017

and

December 31, 2016:

September 30 , 201 7 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	102,220	$	1,417	$	103,637
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				47		47
P artnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				723		723
Total	$	412,000	$	80,770	$	492,770
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		197		197
Unamortized Long-Term Debt Issuance Costs		1,687		480		2,167
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,313	$	80,093	$	490,406
Total Short-Term and Long-Term Debt (with current maturities)	$	512,533	$	81,707	$	594,240

December 31, 2016 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	42,883	$	--	$	42,883
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	15,000	$	15,000
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
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				106		106
PACE Note, 2.54%, due March 18, 2021				836		836
Total	$	445,000	$	95,942	$	540,942
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,970		231		33,201
Unamortized Long-Term Debt Issuance Costs		1,861		539		2,400
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,169	$	95,172	$	505,341
Total Short-Term and Long-Term Debt (with current maturities)	$	486,022	$	95,403	$	581,425

XML

Note 11 - Pension Plan and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Pension and Other Postretirement Benefits Disclosure [Text Block]

1

1

.

Pension Plan and Other Postretirement Benefits

Pension Plan

—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			201 6
Service Cost —Benefit Earned During the Period	$	1,407		$	1,376		$	4,221		$	4,139
Interest Cost on Projected Benefit Obligation		3,534			3,603			10,604			10,646
Expected Return on Assets		(4,807	)		(4,857	)		(14,421	)		(14,590	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			48			89			142
From Other Comprehensive Income 1		1			1			3			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,411			3,818			3,865
From Other Comprehensive Income 1		31			32			94			95
Net Periodic Pension Cost	$	1,469		$	1,614		$	4,408		$	4,300

1

Corporate cost included in Other Nonelectric Expenses.

 

Cash flows

—The Company currently is

not

required and does

not

anticipate making a contribution to its pension plan in

2017.

The Company made a discretionary plan contribution totaling

$10.0

million in

January 2016.

Executive Survivor and Supplemental Retirement Plan

—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	201 7		201 6		201 7		201 6
Service Cost —Benefit Earned During the Period	$	73	$	63	$	218	$	189
Interest Cost on Projected Benefit Obligation		421		417		1,264		1,251
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4		12		12
From Other Comprehensive Income 1		10		9		29		28
Amortization of Net Actuarial Loss:
From Regulatory Asset		70		74		213		220
From Other Comprehensive Income 2		110		111		330		334
Net Periodic Pension Cost	$	688	$	678	$	2,066	$	2,034
1 Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	3	$	12	$	11
Other Nonelectric Expenses		6		6		17		17
2 Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	67	$	68	$	199	$	204
Other Nonelectric Expenses		43		43		131		130

Postretirement Benefits

—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			201 6
Service Cost —Benefit Earned During the Period	$	357		$	365		$	1,069		$	976
Interest Cost on Projected Benefit Obligation		678			794			2,034			1,877
Amortization of Prior-Service Cost:
From Regulatory Asset		--			34			--			100
From Other Comprehensive Income 1		--			1			--			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			284			699			284
From Other Comprehensive Income 1		5			7			17			7
Net Periodic Postretirement Benefit Cost	$	1,273		$	1,485		$	3,819		$	3,247
Effect of Medicare Part D Subsidy	$	(141	)	$	(177	)	$	(421	)	$	(692	)
1 Corporate cost included in Other Nonelectric Expenses.

XML

Note 12 - Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Fair Value Disclosures [Text Block]

1

2

. Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash

Equivalents

—The carrying amount approximates fair value because of the short-term maturity of those instruments.

Short-Term Debt

—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of

September 30, 2017

and

December 31, 2016

related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of

LIBOR

plus

1.75%

and

LIBOR

plus

1.25%

,

respectively, which approximate market rates.

Long

-Term Debt

including Current Maturities

—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level

2

of the fair value hierarchy set forth in ASC 

820.

	September 30, 2017						December 31, 20 16
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents		826			826			--			--
Short -Term Debt		(103,637	)		(103,637	)		(42,883	)		(42,883	)
Long -Term Debt including Current Maturities		(490,603	)		(543,870	)		(538,542	)		(583,835	)

XML

Note 14 - Income Tax Expense - Continuing Operations

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Income Tax Disclosure [Text Block]

1

4

. 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)	201 7			201 6			201 7			201 6
Income Before Income Taxes – Continuing Operations	$	24,808		$	19,757		$	73,314		$	60,378
Tax Computed at Company ’s Net Composite Federal and State Statutory Rate (39%)		9,675			7,705			28,592			23,547
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,349	)		(1,423	)		(5,411	)		(4,994	)
Section 199 Domestic Production Activities Deduction		(330	)		(9	)		(990	)		(207	)
Excess Tax Deduction – 2014 Performance Share Awards		--			--			(697	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)		(637	)		(637	)
Corporate -Owned Life Insurance		(118	)		(92	)		(620	)		(664	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(157	)		(517	)		(472	)
R&D Tax Credits		(148	)		(223	)		(454	)		(445	)
Investment Tax Credits		(41	)		(87	)		(122	)		(262	)
Other Items – Net		(270	)		(339	)		151			(128	)
Income Tax Expense – Continuing Operations	$	7,035		$	5,163		$	19,295		$	15,738
Effective Income Tax Rate – Continuing Operations		28.4	%		26.1	%		26.3	%		26.1	%

The following table summarizes the activity related to

our unrecognized tax benefits:

(in thousands)	201 7			201 6
Balance on January 1	$	891		$	468
Increases Related to Tax Positions for Prior Years		28			40
Increases Related to Tax Positions for Current Year		220			26
Uncertain Positions Resolved During Year		(206	)		(97	)
Balance on September 30	$	933		$	437

The balance of unrecognized tax benefits as of

September 30, 2017

would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of

September 30, 2017

is

not

expected to change significantly within the next

12

 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was

no

amount accrued for interest on tax uncertainties as of

September 30, 2017.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of

September 30, 2017,

with limited exceptions, the Company is

no

longer subject to examinations by taxing authorities for tax years prior to

2014

for federal and North Dakota state income taxes and prior to

2013

for Minnesota

state income taxes.

XML

Note 16 - Discontinued Operations

9 Months Ended

Sep. 30, 2017

Notes to Financial Statements

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

1

6

. Discontinued Operations

Included in discontinued operations are activities related to

the Company’s former wind tower manufacturing, dock and boatlift and construction companies. Included in liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:

(in thousands)	201 7			201 6
Warranty Reserve Balance, January 1	$	1,369		$	2,103
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(112	)		(24	)
Decrease in Warranty Estimates for Prior Years		(400	)		(530	)
Warranty Reserve Balance, September 30	$	857		$	1,549

The warranty reserve balances as of

September 30, 2017

relate to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried

fifteen

year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.

Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on

one

defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company

’s consolidated net income and financial condition.

XML

Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable

and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.

For the Company

’s operating companies recognizing revenue on certain products when shipped, those operating companies have

no

further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.

Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block]

Agreements Subject to Legally Enforceable Netting Arrangements

The Company does

not

offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurements

The Company follows

Accounting Standards Codification (ASC) Topic

820,

Fair Value Measurements and Disclosures

(ASC

820

), for recurring fair value measurements. ASC

820

provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The

three

levels defined by the hierarchy and examples of each level are as follows:

Level

1

– Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level

1

are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).

Level

2

– Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level

2

are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level

3

– Significant inputs to pricing have little or

no

observability as of the reporting date. The types of assets and liabilities included in Level

3

are those with inputs requiring significant management judgment or estimation and

may

include complex and subjective models and forecasts.

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, 2017

and

December 31, 2016:

September 30 , 201 7 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,275
Corporate Debt Securities – Held by Captive Insurance Company			$	5,039
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,099
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		714
Total Assets	$	1,989	$	7,138

December 31, 201 6 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,280
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,945
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	849
Total Assets	$	849	$	8,225

The valuation techniques and inputs used for the Level

2

fair value measurements in the table above are as follows:

Government-Backed and Government-Sponsored Enterprises

’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company

– Fair values are determined on the basis of valuations provided by a

third

-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service

may

be based on broker quotes.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Coyote Station Lignite Supply Agreement

– Variable Interest Entity

—In

October 2012

the Coyote Station owners, including Otter Tail Power Company (OTP), entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in

May 2016

and ending in

December 2040.

The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from

May 2016

through

December 2040

and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements.

No

single owner of Coyote Station owns a majority interest in Coyote Station and

none,

individually, has the power to direct the activities that most significantly impact CCMC. Therefore,

none

of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is

not

required to include CCMC in its consolidated financial statements.

If the LSA terminates prior to the expiration of its term or the production period terminates prior to

December 31, 2040

and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC

’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of

September 30, 2017

could be as high as

$58.0

 million, OTP’s

35%

share of unrecovered costs.

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)	201 7		201 6
Finished Goods	$	19,500	$	27,755
Work in Process		13,885		11,754
Raw Material, Fuel and Supplies		45,530		44,231
Total Inventories	$	78,915	$	83,740

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, 2016

indicated the fair values are substantially in excess of their respective book values and

not

impaired.

The following table

indicates there were

no

changes to goodwill by business segment during the

first

nine

months of

2017:

(in thousands)	Gross Balance December 31, 2016		Accumulated Impairments		Balance (net of impairments) December 31, 2016		Adjustments to Goodwill in 201 7		Balance (net of impairments) September 30, 2017
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, 2017

and

December 

31,

 

2016:

September 30 , 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,710	$	13,781	27	-	215
Covenant not to Compete		590		410		180		11
Other		140		4		136		35
Total	$	23,221	$	9,124	$	14,097
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36	-	224
Covenant not to Compete		590		262		328		20
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	201 7		201 6		201 7		201 6
Amortization Expense – Intangible Assets	$	336	$	348	$	1,001	$	1,103

The estimated annual amortization expense for these intangible assets for the next

five

years is:

(in thousands)	2017		2018		2019		2020		2021
Estimated Amortization Expense – Intangible Assets	$	1,346	$	1,313	$	1,181	$	1,131	$	1,099

Cash Flow Supplemental [Policy Text Block]

Supplemental Disclosures of Cash Flow Information

	As of September 30,
(in thousands)	201 7		201 6
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	17,940	$	11,552

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Standards

Adopted

Accounting Standards Update (

ASU

)

2015

-

11

—In

July 2015

the Financial Accounting Standards Board (FASB) issued ASU

No.

2015

-

11,

Inventory (Topic

330

): Simplifying the Measurement of Inventory,

which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update was effective prospectively for fiscal years and interim periods beginning after

December 15, 2016.

The Company adopted the updates in ASU

2015

-

11

in the

first

quarter of

2017.

The adoption of the updated standard did

not

have a material impact on the Company’s consolidated financial statements as market and net realizable value were substantially the same for the inventories of its manufacturing companies.

New Accounting Standards

Pending

Adopt

ion

ASU

2014

-

09

—In

May 2014

the FASB issued ASU

No.

2014

-

09,

Revenue from Contracts with Customers (Topic

606

)

(ASC

606

). ASC

606

is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC

606

also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

Amendments to the ASC in ASU

2014

-

09,

as amended, are effective for fiscal years beginning after

December 15, 2017.

Early adoption is permitted, but

not

any earlier than

January 1, 2017.

Application methods permitted are: (

1

) full retrospective, (

2

) retrospective using

one

or more practical expedients and (

3

) retrospective with the cumulative effect of initial application recognized at the date of initial

application. The Company does

not

plan to adopt the updated guidance prior to

January 1, 2018.

As of

September 30, 2017

the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU

2014

-

09

will be applicable and is developing controls for new processes that will be required to track and report revenues where the timing of revenue recognition will change under ASU

2014

-

09.

Based on review of the Company’s revenue streams, the Company does

not

anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU

2014

-

09.

The Company will adopt the updates in ASU

2014

-

09

on a modified retrospective basis with the cumulative effect of initial application on retained earnings and other balance sheet accounts, if any, recognized on

January 1, 2018,

the date of initial application. Adoption of ASU

2014

-

09

will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that

may

be required to be reported under the updated standard.

ASU

2016

-

02

—In

February 2016

the FASB issued ASU

No.

2016

-

02,

Leases (Topic

842

)

(ASU

2016

-

02

). ASU

2016

-

02

is a comprehensive amendment of the ASC, creating Topic

842,

which will supersede the current requirements under ASC Topic

840

on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic

842

affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic

842

is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic

842

retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic

842

also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU

2016

-

02

are effective for fiscal years beginning after

December 15, 2018,

including interim periods within those fiscal years. Early application of the amendments in ASU

2016

-

02

is permitted. The Company is currently reviewing ASU

2016

-

02,

has developed a list of all current leases outstanding and is identifying key impacts to its businesses to determine areas where the amendments in ASU

2016

-

02

will be applicable and is evaluating transition options. The Company does

not

currently plan to apply the amendments in ASU 

2016

-

02

to its consolidated financial statements prior to

2019.

ASU

2017

-

04

—In

January 2017

the FASB issued ASU

No.

2017

-

04,

Intangibles—Goodwill and Other (Topic

350

): Simplifying the Test for Goodwill Impairment

(ASU

2017

-

04

), which

simplifies how an entity is required to test goodwill for impairment by eliminating Step

2

from the goodwill impairment test. Step

2

measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill.

In computing the implied fair value of goodwill under Step

2,

an entity had to perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination.

Under the amendments in ASU

2017

-

04,

an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will

not

exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.

The amendments in

ASU

2017

-

04

modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity

no

longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step

2

from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU

2017

-

04

are effective for annual or any interim goodwill impairment tests in fiscal years beginning after

December 15, 2019.

Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after

January 1, 2017.

ASU

2017

-

07

—In

March 2017

the FASB issued ASU

No.

2017

-

07,

Compensation—Retirement Benefits (Topic

715

): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

(ASU

2017

-

07

), which

is intended

to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost.

ASC

Topic

715,

Compensation—Retirement Benefits

(ASC

715

)

,

does

not

prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does

not

require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets.

The amendments in ASU

2017

-

07

require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost as defined in ASC

715

are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in ASU

2017

-

07

also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU

2017

-

07

are effective for annual periods beginning after

December 15, 2017,

including interim periods within those annual periods. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets.

The majority of the Company

’s benefit costs to which the amendments in ASU

2017

-

07

apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU

2017

-

07

deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU

2017

-

07

may

have on its consolidated financial statements, financial position and results of operations and is determining the adjustments and regulatory assets to be established in order to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under the ASU

2017

-

07

amendments to GAAP. The non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on the Company’s consolidated income statements upon adoption of the amendments in ASU

2017

-

07.

T

he Company’s non-service costs components of net periodic post-retirement benefit costs that will be capitalized to plant in service in

2017

but that would be recorded as regulatory assets if the amendments in ASU

2017

-

07

were applicable in

2017

are expected to be

$0.7

million. The Company’s non-service costs components of net periodic post-retirement benefit costs included in operating expense in

2017

that would be included in other income and deductions under ASU

2017

-

07

are expected to be

$5.7

million. The Company does

not

plan to adopt the updates in ASU 

2017

-

07

prior to the

first

quarter of

2018,

the required effective period for application of the updates by the Company.

XML

Note 1 - Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

September 30 , 201 7 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Equity Funds – Held by Captive Insurance Company	$	1,275
Corporate Debt Securities – Held by Captive Insurance Company			$	5,039
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,099
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan		714
Total Assets	$	1,989	$	7,138

December 31, 201 6 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,280
Government -Backed and Government-Sponsored Enterprises ’ Debt Securities – Held by Captive Insurance Company				2,945
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	849
Total Assets	$	849	$	8,225

Schedule of Inventory, Current [Table Text Block]

	September 30,		December 31,
(in thousands)	201 7		201 6
Finished Goods	$	19,500	$	27,755
Work in Process		13,885		11,754
Raw Material, Fuel and Supplies		45,530		44,231
Total Inventories	$	78,915	$	83,740

Schedule of Goodwill [Table Text Block]

(in thousands)	Gross Balance December 31, 2016		Accumulated Impairments		Balance (net of impairments) December 31, 2016		Adjustments to Goodwill in 201 7		Balance (net of impairments) September 30, 2017
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 , 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods (months)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,710	$	13,781	27	-	215
Covenant not to Compete		590		410		180		11
Other		140		4		136		35
Total	$	23,221	$	9,124	$	14,097
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36	-	224
Covenant not to Compete		590		262		328		20
Total	$	23,081	$	8,123	$	14,958

Finite-lived Intangible Assets Amortization Expense [Table Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	201 7		201 6		201 7		201 6
Amortization Expense – Intangible Assets	$	336	$	348	$	1,001	$	1,103

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

(in thousands)	2017		2018		2019		2020		2021
Estimated Amortization Expense – Intangible Assets	$	1,346	$	1,313	$	1,181	$	1,131	$	1,099

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	As of September 30,
(in thousands)	201 7		201 6
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	17,940	$	11,552

XML

Note 2 - Segment Information (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	103,399		$	102,723		$	324,186		$	313,642
Manufacturing		54,355			52,171			172,076			170,443
Plastics		58,708			42,292			146,416			122,841
Intersegment Eliminations		(5	)		(11	)		(18	)		(27	)
Total	$	216,457		$	197,175		$	642,660		$	606,899

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in thousands)	201 7		201 6		201 7		201 6
Electric	$	6,362	$	6,304	$	19,187	$	18,744
Manufacturing		555		974		1,662		2,972
Plastics		157		273		483		796
Corporate and Intersegment Eliminations		319		475		1,050		1,484
Total	$	7,393	$	8,026	$	22,382	$	23,996

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	3,548		$	4,730		$	12,052		$	11,262
Manufacturing		676			182			3,304			2,992
Plastics		3,826			1,577			8,074			5,206
Corporate		(1,015	)		(1,326	)		(4,135	)		(3,722	)
Total	$	7,035		$	5,163		$	19,295		$	15,738

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	201 7			201 6			201 7			201 6
Electric	$	10,869		$	12,513		$	36,563		$	34,199
Manufacturing		1,608			1,246			6,735			6,108
Plastics		6,092			2,346			13,166			7,983
Corporate		(796	)		(1,511	)		(2,445	)		(3,650	)
Discontinued Operations		(39	)		22			78			171
Total	$	17,734		$	14,616		$	54,097		$	44,811

	September 30,		December 31,
(in thousands)	201 7		201 6
Electric	$	1,660,591	$	1,622,231
Manufacturing		167,004		166,525
Plastics		98,283		84,592
Corporate		41,019		39,037
Total	$	1,966,897	$	1,912,385

XML

Note 3 - Rate and Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Interim Revenue [Table Text Block]

Interim Revenue (in thousands)	April 16, 2016 through September 30, 2017
Billed		$	21,847
Accrued Refund		$	8,237
Net Interim Revenue		$	13,610
Interest on Refundable Amount		$	233
Refund Liability as of September 30, 2017		$	8,470

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
2016 Incentive and Cost Recovery	A – September 15, 2017	October 1, 201 7	$	9,868		$0.00 536/kwh
2015 Incentive and Cost Recovery	A – July 19, 2016	October 1, 2016	$	8,590		$0.00275/kwh
2014 Incentive and Cost Recovery	A – July 10, 2015	October 1, 2015	$	8,689		$0.00287/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
2014 Annual Update	A – February 18, 2015	March 1, 2015	$	8,388		Various
Environmental Cost Recovery
2017 Rate Reset	A – October 30, 2017	November 1, 2017	$	(1,943	)	- 0.935% of Rev
2016 Annual Update	A – July 5, 2016	September 1, 2016	$	11,884		6.927% of Rev
2015 Annual Update	A – March 9, 2016	October 1, 2015	$	12,104		7.006% of Rev
North Dakota
Renewable Resource Adjustment
201 6 Annual Update	A – March 15, 2017	April 1, 2017	$	9,156		7.00 5% of Rev
2015 Annual Update	A – June 22, 2016	July 1, 2016	$	9,262		7. 573% of Rev
201 4 Annual Update	A – March 25, 2015	April 1, 2015	$	5,441		4.069% of Rev
Transmission Cost Recovery
201 7 Annual Update	R – August 31, 2017	January 1, 2018	$	8,593		Various
201 6 Annual Update	A – December 14, 2016	January 1, 2017	$	6,916		Various
2015 Annual Update	A – December 16, 2015	January 1, 2016	$	9,985		Various
Environmental Cost Recovery
201 7 Annual Update	A – July 12, 2017	August 1, 2017	$	9,917		7.633% of base
201 6 Annual Update	A – June 22, 2016	July 1, 2016	$	10,359		7. 904% of base
2015 Annual Update	A – June 17, 2015	July 1, 2015	$	12,249		9.193 % of base
South Dakota
Transmission Cost Recovery
201 6 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
2014 Annual Update	A – February 13, 2015	March 1, 2015	$	1,538		Various
Environmental Cost Recovery
2017 Annual Update	A – October 13, 2017	November 1, 2017	$	2,082		$0.00 483/kwh
201 6 Annual Update	A – October 26, 2016	November 1, 2016	$	2,238		$0.00536/kwh
201 5 Annual Update	A – October 15, 2015	November 1, 2015	$	2,728		$0.00643/kwh

Schedule of Revenues Recorded under Rate Riders [Table Text Block]

Revenues Recorded under Rider Rates	Three Months Ended September 30,					Nine Months Ended September 30,
Rate Rider (in thousands)	2017			2016		2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives 1	$	2,499		$	2,839	$	6,567	$	7,554
Transmission Cost Recovery		(594	)		779		2,849		4,188
Environmental Cost Recovery		1,669			3,127		7,305		9,362
North Dakota
Renewable Resource Adjustment		2,213			2,170		5,822		6,151
Transmission Cost Recovery		2,410			1,950		6,305		6,155
Environmental Cost Recovery		2,396			2,762		7,272		8,344
South Dakota
Transmission Cost Recovery		596			335		1,324		1,397
Environmental Cost Recovery		613			691		1,755		1,951
Conservation Improvement Program Costs and Incentives		104			135		520		418

Minnesota 2016 General Rate Case Information [Member]

Notes Tables

Public Utilities General Disclosures [Table Text Block]

($ in thousands)	Interim Rates Authorized April 14, 2016			Final Rates
Revenue Increase – Annualized based on Test Year Data	$	16,816		$	12,100
Revenue Percent Increase		9.56	%		6.23	%
Return on Rate Base		8.07	%		7.5056	%
Jurisdictional Rate Base based on Test Year Data	$	483,000		$	471,000
Return on Equity		10.1	%		9.41	%
Based on Equity to Total Capital of		52.50	%		52.50	%
Debt to Total Capital		47.50	%		47.50	%

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Note 4 - Regulatory Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Regulatory Assets and Liabilities [Table Text Block]

	September 30, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	6,444	$	103,434	$	109,878	see below
Conservation Improvement Program Costs and Incentives 2		8,230		2,351		10,581		24
Deferred Marked-to-Market Losses 1		4,063		3,420		7,483		39
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,525		6,525	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2		88		2,432		2,520		27
Big Stone II Unrecovered Project Costs – Minnesota 1		658		1,597		2,255		43
Debt Reacquisition Premiums 1		252		1,026		1,278		180
Recoverable Fuel and Purchased Power Costs 1		885		--		885		12
Deferred Income Taxes 1		--		833		833	asset lives
North Dakota Renewable Resource Rider Accrued Revenues 2		189		585		774		18
Big Stone II Unrecovered Project Costs – South Dakota 2		100		467		567		68
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		496		--		496		7
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		142		--		142		3
South Dakota Transmission Cost Recovery Rider Accrued Revenues 2		35		--		35		3
Total Regulatory Assets	$	21,582	$	122,670	$	144,252
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	82,485	$	82,485	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		1,808		616		2,424		24
Minnesota Environmental Cost Recovery Rider Accrued Refund		1,722		--		1,722		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		716		342		1,058		15
Deferred Income Taxes		--		720		720	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		385		--		385		7
South Dakota Environmental Cost Recovery Rider Accrued Refund		252		--		252		12
Sout h Dakota Transmission Cost Recovery Rider Accrued Refund		172		--		172		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		99		33		132		15
Other		6		85		91		195
Nort h Dakota Environmental Cost Recovery Rider Accrued Refund		43		--		43		12
Total Regulatory Liabilities	$	5,203	$	84,281	$	89,484
Net Regulatory Asset Position	$	16,379	$	38,389	$	54,768

	December 31, 2016						Remaining Recovery/
(in thousands)	Current		Long-Term		Total			Refund Period (months)
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1	$	6,443	$	108,267	$	114,710	see below
Conservation Improvement Program Costs and Incentives 2		4,836		5,158		9,994		21
Deferred Marked-to-Market Losses 1		4,063		6,467		10,530		48
Accumulated ARO Accretion/Depreciation Adjustment 1		--		6,153		6,153	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2		333		--		333		12
Big Stone II Unrecovered Project Costs – Minnesota 1		778		2,087		2,865		52
Debt Reacquisition Premiums 1		325		1,214		1,539		189
Recoverable Fuel and Purchased Power Costs 1		1,798		--		1,798		12
Deferred Income Taxes 1		--		1,014		1,014	asset lives
North Dakota Renewable Resource Rider Accrued Revenues 2		1,319		482		1,801		15
Big Stone II Unrecovered Project Costs – South Dakota 2		100		543		643		77
Minnesota Deferred Rate Case Expenses Subject to Recovery 1		1,082		--		1,082		12
North Dakota Transmission Cost Recovery Rider Accrued Revenues 2		--		568		568		24
South Dakota Transmission Cost Recovery Rider Accrued Revenues 2		73		141		214		14
North Dakota Environmental Cost Recovery Rider Accrued Revenues 2		113		--		113		12
Minnesota Renewable Resource Rider Accrued Revenues 2		34		--		34		9
Total Regulatory Assets	$	21,297	$	132,094	$	153,391
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	--	$	80,404	$	80,404	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund		757		--		757		12
Minnesota Environmental Cost Recovery Rider Accrued Refund		139		--		139		12
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,381		782		2,163		24
Deferred Income Taxes		--		818		818	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		208		919		16
South Dakota Environmental Cost Recovery Rider Accrued Refund		285		--		285		12
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		--		132		132		24
Other		21		89		110		204
Total Regulatory Liabilities	$	3,294	$	82,433	$	85,727
Net Regulatory Asset Position	$	18,003	$	49,661	$	67,664

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Note 5 - Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Derivative Asset and Derivative Liability Balances Subject to Legally Enforceable Netting Arrangements [Table Text Block]

(in thousands)	September 30, 201 7			December 31, 201 6
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	--		$	--
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(13,591	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(13,591	)	$	(17,382	)

Schedule of Credit Derivatives Loss Position [Table Text Block]

(in thousands)	September 30, 2017		December 31, 2016
Loss Contracts Covered by Deposited Funds or Letters of Credit	$	--	$	--
Contracts Requiring Cash Deposits if OTP ’s Credit Falls Below Investment Grade 1		13,591		17,382
Total Loss Contracts based on Current Market Values	$	13,591	$	17,382
1 Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
Contracts Requiring Cash Deposits if OTP ’s Credit Falls Below Investment Grade	$	13,591	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		--		--
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	13,591	$	17,382

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Note 6 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Stockholders Equity [Table Text Block]

(in thousands)	Par Value, Common Shares			Premium on Common Shares			Retained Earnings			Accumulated Other Comprehensive Income/(Loss)			Total Common Equity
Balance, December 31, 201 6	$	196,741		$	337,684		$	139,479		$	(3,800	)	$	670,104
Common Stock Issuances, Net of Expenses		1,285			3,684									4,969
Common Stock Retirements		(239	)		(1,560	)								(1,799	)
Net Income								54,097						54,097
Other Comprehensive Income											341			341
Employee Stock Incentive Plan s Expense					2,765									2,765
Common Dividends ($0. 96 per share)								(37,958	)					(37,958	)
Balance, September 30, 2017	$	197,787		$	342,573		$	155,618		$	(3,459	)	$	692,519

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

Common Shares Outstanding December 31, 201 6	39,348,136
Issuances:
Executive Stock Performance Awards (2014 shares earned)	89,291
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested	68,235
Cash Invested	29,463
Vesting of Restricted Stock Units	22,225
Restricted Stock Issued to Directors	17,600
Employee Stock Ownership Plan	14,835
Employee Stock Purchase Plan:
Dividends Reinvested	9,566
Cash Invested	5,284
Directors Deferred Compensation	560
Retirements:
Shares Withheld for Individual Income Tax Requirements	(47,704	)
Common Shares Outstanding September 30, 2017	39,557,491

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Three Months ended September 30				Nine Months ended September 30
	201 7		201 6		201 7		201 6
Weighted Average Common Shares Outstanding – Basic		39,507,581		38,832,659		39,440,416		38,316,324
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		211,996		103,084		195,869		80,450
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		55,975		48,645		54,645		42,620
Nonvested Restricted Shares		16,982		18,029		18,923		14,556
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		2,832		3,289		3,009		3,451
Total Dilutive Shares		287,785		173,047		272,446		141,077
Weighted Average Common Shares Outstanding – Diluted		39,795,366		39,005,706		39,712,862		38,457,401

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Note 7 - Share-based Payments (Tables)

9 Months Ended

Sep. 30, 2017

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 2, 2017		59,500	$	31.00	December 31, 2019
Restricted Stock Units Granted to Executive Officers	February 2, 2017		15,900	$	37.65	25% per year through February 6, 2021
Restricted Stock Units Granted to Key Employees	April 10, 2017		9,995	$	32.78	100% on April 8, 20 21
	September 25, 2017		1,000	$	38.29	100% on April 8, 2021
Restricted Stock Granted to Nonemployee Directors	April 10, 2017		17,600	$	37.75	25% per year through April 8, 20 21

Share-based Compensation, Activity [Table Text Block]

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	201 7		201 6		201 7		201 6
Stock Performance Awards Granted to Executive Officers	$	494	$	455	$	1,568	$	1,296
Restricted Stock Units Granted to Executive Officers		104		64		472		373
Restricted Stock Granted to Executive Officers		16		22		54		73
Restricted Stock Granted to Nonemployee Directors		144		128		416		363
Restricted Stock Units Granted to Key Employees		87		62		255		207
Employee Stock Purchase Plan (15% discount)		--		47		--		135
Totals	$	845	$	778	$	2,765	$	2,447

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Note 10 - Short-term and Long-term Borrowings (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Line of Credit Facilities [Table Text Block]

(in thousands)	Line Limit		In Use on September 30, 2017		Restricted due to Outstanding Letters of Credit		Available on September 30, 2017		Available on December 31, 201 6
Otter Tail Corporation Credit Agreement	$	130,000	$	1,417	$	--	$	128,583	$	130,000
OTP Credit Agreement		170,000		102,220		300		67,480		127,067
Total	$	300,000	$	103,637	$	300	$	196,063	$	257,067

Schedule of Debt [Table Text Block]

September 30 , 201 7 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	102,220	$	1,417	$	103,637
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				47		47
P artnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				723		723
Total	$	412,000	$	80,770	$	492,770
Less: Current Maturities net of Unamortized Debt Issuance Costs		--		197		197
Unamortized Long-Term Debt Issuance Costs		1,687		480		2,167
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,313	$	80,093	$	490,406
Total Short-Term and Long-Term Debt (with current maturities)	$	512,533	$	81,707	$	594,240

December 31, 2016 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	42,883	$	--	$	42,883
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	15,000	$	15,000
3.55% Guaranteed Senior Notes, due December 15, 2026				80,000		80,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017	$	33,000				33,000
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				106		106
PACE Note, 2.54%, due March 18, 2021				836		836
Total	$	445,000	$	95,942	$	540,942
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,970		231		33,201
Unamortized Long-Term Debt Issuance Costs		1,861		539		2,400
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,169	$	95,172	$	505,341
Total Short-Term and Long-Term Debt (with current maturities)	$	486,022	$	95,403	$	581,425

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Note 11 - Pension Plan and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Net Benefit Costs [Table Text Block]

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			201 6
Service Cost —Benefit Earned During the Period	$	1,407		$	1,376		$	4,221		$	4,139
Interest Cost on Projected Benefit Obligation		3,534			3,603			10,604			10,646
Expected Return on Assets		(4,807	)		(4,857	)		(14,421	)		(14,590	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			48			89			142
From Other Comprehensive Income 1		1			1			3			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,411			3,818			3,865
From Other Comprehensive Income 1		31			32			94			95
Net Periodic Pension Cost	$	1,469		$	1,614		$	4,408		$	4,300

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	201 7		201 6		201 7		201 6
Service Cost —Benefit Earned During the Period	$	73	$	63	$	218	$	189
Interest Cost on Projected Benefit Obligation		421		417		1,264		1,251
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4		12		12
From Other Comprehensive Income 1		10		9		29		28
Amortization of Net Actuarial Loss:
From Regulatory Asset		70		74		213		220
From Other Comprehensive Income 2		110		111		330		334
Net Periodic Pension Cost	$	688	$	678	$	2,066	$	2,034
1 Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	3	$	12	$	11
Other Nonelectric Expenses		6		6		17		17
2 Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	67	$	68	$	199	$	204
Other Nonelectric Expenses		43		43		131		130

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2017			201 6
Service Cost —Benefit Earned During the Period	$	357		$	365		$	1,069		$	976
Interest Cost on Projected Benefit Obligation		678			794			2,034			1,877
Amortization of Prior-Service Cost:
From Regulatory Asset		--			34			--			100
From Other Comprehensive Income 1		--			1			--			3
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			284			699			284
From Other Comprehensive Income 1		5			7			17			7
Net Periodic Postretirement Benefit Cost	$	1,273		$	1,485		$	3,819		$	3,247
Effect of Medicare Part D Subsidy	$	(141	)	$	(177	)	$	(421	)	$	(692	)
1 Corporate cost included in Other Nonelectric Expenses.

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Note 12 - Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Fair Value, by Balance Sheet Grouping [Table Text Block]

	September 30, 2017						December 31, 20 16
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and Cash Equivalents		826			826			--			--
Short -Term Debt		(103,637	)		(103,637	)		(42,883	)		(42,883	)
Long -Term Debt including Current Maturities		(490,603	)		(543,870	)		(538,542	)		(583,835	)

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Note 14 - Income Tax Expense - Continuing Operations (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	201 7			201 6			201 7			201 6
Income Before Income Taxes – Continuing Operations	$	24,808		$	19,757		$	73,314		$	60,378
Tax Computed at Company ’s Net Composite Federal and State Statutory Rate (39%)		9,675			7,705			28,592			23,547
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(1,349	)		(1,423	)		(5,411	)		(4,994	)
Section 199 Domestic Production Activities Deduction		(330	)		(9	)		(990	)		(207	)
Excess Tax Deduction – 2014 Performance Share Awards		--			--			(697	)		--
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)		(637	)		(637	)
Corporate -Owned Life Insurance		(118	)		(92	)		(620	)		(664	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(157	)		(517	)		(472	)
R&D Tax Credits		(148	)		(223	)		(454	)		(445	)
Investment Tax Credits		(41	)		(87	)		(122	)		(262	)
Other Items – Net		(270	)		(339	)		151			(128	)
Income Tax Expense – Continuing Operations	$	7,035		$	5,163		$	19,295		$	15,738
Effective Income Tax Rate – Continuing Operations		28.4	%		26.1	%		26.3	%		26.1	%

Summary of Income Tax Contingencies [Table Text Block]

(in thousands)	201 7			201 6
Balance on January 1	$	891		$	468
Increases Related to Tax Positions for Prior Years		28			40
Increases Related to Tax Positions for Current Year		220			26
Uncertain Positions Resolved During Year		(206	)		(97	)
Balance on September 30	$	933		$	437

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Note 16 - Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2017

Notes Tables

Schedule of Product Warranty Liability [Table Text Block]

(in thousands)	201 7			201 6
Warranty Reserve Balance, January 1	$	1,369		$	2,103
Additional Provision for Warranties Made During the Year		--			--
Settlements Made During the Year		(112	)		(24	)
Decrease in Warranty Estimates for Prior Years		(400	)		(530	)
Warranty Reserve Balance, September 30	$	857		$	1,549

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Note 1 - Summary of Significant Accounting Policies (Details Textual) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Pro Forma [Member] | Accounting Standards Update 2017-07 [Member]
Postretirement Benefit Plan, Nonservice Costs Capitalized to Plant in Service During Fiscal Year	$ 0.7
Postretirement Benefit Plan, Nonservice Costs Included in Operating Expense During Fiscal Year	5.7
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	$ 58.0
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage	35.00%

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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, 2017	Dec. 31, 2016
Fair Value, Inputs, Level 1 [Member]
Total Assets	$ 1,989	$ 849
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member]
Investments	1,275
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member]
Investments
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member]
Other Assets	714	849
Fair Value, Inputs, Level 2 [Member]
Total Assets	7,138	8,225
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member]
Investments
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Investments	5,039	5,280
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member]
Investments	2,099	2,945
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member]
Other Assets

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Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Finished Goods	$ 19,500	$ 27,755
Work in Process	13,885	11,754
Raw Material, Fuel and Supplies	45,530	44,231
Total Inventories	$ 78,915	$ 83,740

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Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Gross Balance		$ 37,572
Accumulated Impairments
Balance	$ 37,572	37,572
Adjustments to Goodwill
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

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Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Amortizable Intangible Assets:
Gross Carrying Amount	$ 23,221	$ 23,081
Accumulated Amortization	9,124	8,123
Net Carrying Amount	14,097	14,958
Customer Relationships [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	8,710	7,861
Net Carrying Amount	$ 13,781	$ 14,630
Customer Relationships [Member] | Minimum [Member]
Amortizable Intangible Assets:
Remaining Amortization Periods (Month)	2 years 90 days	3 years
Customer Relationships [Member] | Maximum [Member]
Amortizable Intangible Assets:
Remaining Amortization Periods (Month)	17 years 330 days	18 years 240 days
Covenant Not to Compete [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	$ 590	$ 590
Accumulated Amortization	410	262
Net Carrying Amount	$ 180	$ 328
Remaining Amortization Periods (Month)	330 days	1 year 240 days
Other Intangible Assets [Member]
Amortizable Intangible Assets:
Gross Carrying Amount	$ 140
Accumulated Amortization	4
Net Carrying Amount	$ 136
Remaining Amortization Periods (Month)	2 years 330 days

XML

Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amortization Expense – Intangible Assets	$ 336	$ 348	$ 1,001	$ 1,103

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Note 1 - Summary of Significant Accounting Policies - Estimated Amortization Expense for Intangible Assets (Details) $ in Thousands	Sep. 30, 2017 USD ($)
2017	$ 1,346
2018	1,313
2019	1,181
2020	1,131
2021	$ 1,099

XML

Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Transactions Related to Capital Additions not Settled in Cash	$ 17,940	$ 11,552

XML

Note 2 - Segment Information (Details Textual)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Number of Reportable Segments			3
Operating Revenues [Member] | UNITED STATES
Concentration Risk, Percentage	97.90%	98.50%	98.20%	98.60%

XML

Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Annual Revenue	$ 216,457	$ 197,175	$ 642,660	$ 606,899
Interest Charges	7,393	8,026	22,382	23,996
Income Tax Expense—Continuing Operations	7,035	5,163	19,295	15,738
Net Income	17,734	14,616	54,097	44,811
Assets	1,966,897		1,966,897		$ 1,912,385
Discontinued Operations [Member]
Net Income	(39)	22	78	171
Operating Segments [Member] | Electric [Member]
Annual Revenue	103,399	102,723	324,186	313,642
Interest Charges	6,362	6,304	19,187	18,744
Income Tax Expense—Continuing Operations	3,548	4,730	12,052	11,262
Net Income	10,869	12,513	36,563	34,199
Assets	1,660,591		1,660,591		1,622,231
Operating Segments [Member] | Manufacturing [Member]
Annual Revenue	54,355	52,171	172,076	170,443
Interest Charges	555	974	1,662	2,972
Income Tax Expense—Continuing Operations	676	182	3,304	2,992
Net Income	1,608	1,246	6,735	6,108
Assets	167,004		167,004		166,525
Operating Segments [Member] | Plastics [Member]
Annual Revenue	58,708	42,292	146,416	122,841
Interest Charges	157	273	483	796
Income Tax Expense—Continuing Operations	3,826	1,577	8,074	5,206
Net Income	6,092	2,346	13,166	7,983
Assets	98,283		98,283		84,592
Intersegment Eliminations [Member]
Annual Revenue	(5)	(11)	(18)	(27)
Corporate and Eliminations [Member]
Interest Charges	319	475	1,050	1,484
Income Tax Expense—Continuing Operations	(1,015)	(1,326)	(4,135)	(3,722)
Net Income	(796)	$ (1,511)	(2,445)	$ (3,650)
Assets	$ 41,019		$ 41,019		$ 39,037

XML

Note 3 - Rate and Regulatory Matters (Details Textual)						1 Months Ended		9 Months Ended
	Sep. 28, 2016	Feb. 12, 2015	Nov. 06, 2014	Nov. 12, 2013	Jun. 01, 2011 USD ($)	Jun. 30, 2016	Dec. 22, 2015	Sep. 30, 2017 USD ($)	Nov. 02, 2017 USD ($)	Dec. 31, 2016 USD ($)	May 25, 2016	Apr. 16, 2016	Apr. 15, 2016	Nov. 25, 2009 USD ($)
Regulatory Liabilities								$ 89,484,000		$ 85,727,000
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Current Return on Equity Used in Transmission Rates	10.32%	12.38%		12.38%			10.32%
Proposed Reduced Return on Equity Used in Transmission Rates		8.67%		9.15%		9.70%
Additional Incentive Basis Point			0.50%
Expected Percentage of Return on Equity	10.82%
Regulatory Liabilities								1,600,000		$ 2,700,000
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%
Expected Rate of Financial Incentive Reduction											50.00%
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Fiscal Year 2016 [Member]
Amount Of Financial Incentive Requested								5,000,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Fiscal Year 2015 [Member]
Financial Incentive Request Approved								4,300,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Fiscal Year 2014 [Member]
Financial Incentive Request Approved								3,000,000
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] | The 2016 General Rate Case [Member] | Environmental Cost Recovery Rider [Member]
Revenues Collected Under Riders, Subject to Customer Refund								900,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | Transmission Cost Recovery Rider [Member]
Revenues Collected Under Riders, Subject to Customer Refund								$ 1,400,000
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | ECR and TCR Riders [Member]
Revenues Collected Under Riders, Subject to Refund, Period of Refund								1 year
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member] | Subsequent Event [Member]
General Rate Revenue Increase Requested									$ 13,100,000
Percentage of Increase in Base Rate Revenue Requested									8.70%
Public Utilities, Requested Return on Rate, Percentage									7.97%
Public Utilities, Initial Requested Return on Equity, Percentage									10.30%
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member]
Percentage of Allowed Rate of Return on Rate Base														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 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 - Brookings MVP [Member]
Expanded Capacity of Projects								345
Extended Distance of Transmission Line								70
Current Projected Cost								$ 70,000,000
Percentage of Assets of Project								100.00%
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								$ 78,400,000
Percentage of Assets of Project								100.00%

XML

Note 3 - Rate and Regulatory Matters - Summary of Interim Rate Information (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Apr. 14, 2016
Revenue Increase – Annualized based on Test Year Data, interim rate		$ 16,816
Revenue Increase – Annualized based on Test Year Data, final rates	$ 12,100
Revenue Percent Increase, interim rate		9.56%
Revenue Percent Increase, final rates	6.23%
Return on Rate Base, interim rate		8.07%
Return on Rate Base, final rates	7.5056%
Jurisdictional Rate Base based on Test Year Data, interim rate		$ 483,000
Jurisdictional Rate Base based on Test Year Data, final rates	$ 471,000
Return on Equity, interim rate		10.10%
Return on Equity, final rates	9.41%
Based on Equity to Total Capital of, interim rate		52.50%
Based on Equity to Total Capital of, final rates	52.50%
Debt to Total Capital, interim rate		47.50%
Debt to Total Capital, final rates	47.50%

XML

Note 3 - Rate and Regulatory Matters - Schedule of Interim Revenue (Details) $ in Thousands	18 Months Ended
	Sep. 30, 2017 USD ($)
Billed	$ 21,847
Accrued Refund	8,237
Net Interim Revenue	13,610
Interest on Refundable Amount	233
Refund Liability as of September 30, 2017	$ 8,470

XML

Note 3 - Rate and Regulatory Matters - Summary of Status of Updates for Previous Two Years for Various Rate Riders (Details) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) kWh	Sep. 30, 2016 USD ($)
Annual Revenue		$ 216,457	$ 197,175	$ 642,660	$ 606,899
Otter Tail Power Company [Member] | Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue	[1]	2,499	2,839	$ 6,567	7,554
Otter Tail Power Company [Member] | 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. 01, 2017
Annual Revenue				$ 9,868
Rate (Kilowatt-Hour) | kWh				0.00536
Otter Tail Power Company [Member] | 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. 01, 2016
Annual Revenue				$ 8,590
Rate (Kilowatt-Hour) | kWh				0.00275
Otter Tail Power Company [Member] | Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2014 Incentive and Cost Recovery [Member]
A - Approval Date				Jul. 10, 2015
Effective Date Requested or Approved				Oct. 01, 2015
Annual Revenue				$ 8,689
Rate (Kilowatt-Hour) | kWh				0.00287
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue		(594)	779	$ 2,849	4,188
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date	[2]			Oct. 30, 2017
Effective Date Requested or Approved	[2]			Nov. 01, 2017
Annual Revenue	[2]			$ (3,311)
Rate	[2]			Various
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date				Jul. 05, 2016
Effective Date Requested or Approved				Sep. 01, 2016
Annual Revenue				$ 4,736
Rate				Various
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date				Mar. 09, 2016
Effective Date Requested or Approved				Apr. 01, 2016
Annual Revenue				$ 7,203
Rate				Various
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2014 Annual Update [Member]
A - Approval Date				Feb. 18, 2015
Effective Date Requested or Approved				Mar. 01, 2015
Annual Revenue				$ 8,388
Rate				Various
Otter Tail Power Company [Member] | Minnesota [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue		1,669	3,127	$ 7,305	9,362
Otter Tail Power Company [Member] | Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member]
A - Approval Date				Oct. 30, 2017
Effective Date Requested or Approved				Nov. 01, 2017
Annual Revenue				$ (1,943)
Rate of revenue				(0.935%)
Otter Tail Power Company [Member] | Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member]
A - Approval Date				Jul. 05, 2016
Effective Date Requested or Approved				Sep. 01, 2016
Annual Revenue				$ 11,884
Rate of revenue				6.927%
Otter Tail Power Company [Member] | Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date				Mar. 09, 2016
Effective Date Requested or Approved				Oct. 01, 2015
Annual Revenue				$ 12,104
Rate of revenue				7.006%
Otter Tail Power Company [Member] | North Dakota [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue		2,410	1,950	$ 6,305	6,155
Otter Tail Power Company [Member] | 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. 01, 2017
Annual Revenue				$ 6,916
Rate				Various
Otter Tail Power Company [Member] | North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date				Dec. 16, 2015
Effective Date Requested or Approved				Jan. 01, 2016
Annual Revenue				$ 9,985
Rate				Various
Otter Tail Power Company [Member] | North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member]
Effective Date Requested or Approved				Jan. 01, 2018
Annual Revenue				$ 8,593
Rate				Various
R - Request Date				Aug. 31, 2017
Otter Tail Power Company [Member] | North Dakota [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue		2,396	2,762	$ 7,272	8,344
Otter Tail Power Company [Member] | 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. 01, 2016
Annual Revenue				$ 10,359
Rate of base				7.904%
Otter Tail Power Company [Member] | North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date				Jun. 17, 2015
Effective Date Requested or Approved				Jul. 01, 2015
Annual Revenue				$ 12,249
Rate of base				9.193%
Otter Tail Power Company [Member] | 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. 01, 2017
Annual Revenue				$ 9,917
Rate of base				7.633%
Otter Tail Power Company [Member] | North Dakota [Member] | Renewable Resource Adjustment [Member]
Annual Revenue		2,213	2,170	$ 5,822	6,151
Otter Tail Power Company [Member] | North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member]
A - Approval Date				Mar. 15, 2017
Effective Date Requested or Approved				Apr. 01, 2017
Annual Revenue				$ 9,156
Rate of revenue				7.005%
Otter Tail Power Company [Member] | North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member]
A - Approval Date				Jun. 22, 2016
Effective Date Requested or Approved				Jul. 01, 2016
Annual Revenue				$ 9,262
Rate of revenue				7.573%
Otter Tail Power Company [Member] | North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2014 Annual Update [Member]
A - Approval Date				Mar. 25, 2015
Effective Date Requested or Approved				Apr. 01, 2015
Annual Revenue				$ 5,441
Rate of revenue				4.069%
Otter Tail Power Company [Member] | South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Annual Revenue		104	135	$ 520	418
Otter Tail Power Company [Member] | South Dakota [Member] | Transmission Cost Recovery Rider [Member]
Annual Revenue		596	335	$ 1,324	1,397
Otter Tail Power Company [Member] | 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. 01, 2017
Annual Revenue				$ 2,053
Rate				Various
Otter Tail Power Company [Member] | 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. 01, 2016
Annual Revenue				$ 1,895
Rate				Various
Otter Tail Power Company [Member] | South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2014 Annual Update [Member]
A - Approval Date				Feb. 13, 2015
Effective Date Requested or Approved				Mar. 01, 2015
Annual Revenue				$ 1,538
Rate				Various
Otter Tail Power Company [Member] | South Dakota [Member] | Environmental Cost Recovery Rider [Member]
Annual Revenue		$ 613	$ 691	$ 1,755	$ 1,951
Otter Tail Power Company [Member] | 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. 01, 2016
Annual Revenue				$ 2,238
Rate (Kilowatt-Hour) | kWh				0.00536
Otter Tail Power Company [Member] | South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2015 Annual Update [Member]
A - Approval Date				Oct. 15, 2015
Effective Date Requested or Approved				Nov. 01, 2015
Annual Revenue				$ 2,728
Rate (Kilowatt-Hour) | kWh				0.00643
Otter Tail Power Company [Member] | 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. 01, 2017
Annual Revenue				$ 2,082
Rate (Kilowatt-Hour) | kWh				0.00483

[1] Includes MNCIP costs recovered in base rates.

[2] Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket.

XML

Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues recorded under rate riders		$ 216,457	$ 197,175	$ 642,660	$ 606,899
Otter Tail Power Company [Member] | Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders	[1]	2,499	2,839	6,567	7,554
Otter Tail Power Company [Member] | Minnesota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		(594)	779	2,849	4,188
Otter Tail Power Company [Member] | Minnesota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		1,669	3,127	7,305	9,362
Otter Tail Power Company [Member] | North Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		2,410	1,950	6,305	6,155
Otter Tail Power Company [Member] | North Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		2,396	2,762	7,272	8,344
Otter Tail Power Company [Member] | North Dakota [Member] | Renewable Resource Adjustment [Member]
Revenues recorded under rate riders		2,213	2,170	5,822	6,151
Otter Tail Power Company [Member] | South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member]
Revenues recorded under rate riders		104	135	520	418
Otter Tail Power Company [Member] | South Dakota [Member] | Transmission Cost Recovery Rider [Member]
Revenues recorded under rate riders		596	335	1,324	1,397
Otter Tail Power Company [Member] | South Dakota [Member] | Environmental Cost Recovery Rider [Member]
Revenues recorded under rate riders		$ 613	$ 691	$ 1,755	$ 1,951

[1] Includes MNCIP costs recovered in base rates.

XML

Note 4 - Regulatory Assets and Liabilities (Details Textual)	9 Months Ended
	Sep. 30, 2017
Debt Reacquisition Premiums [Member]
Regulatory Noncurrent Asset Remaining Recovery Period	15 years

XML

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, 2017	Dec. 31, 2016
Regulatory Assets - Current		$ 21,582	$ 21,297
Regulatory Assets - Long -Term		122,670	132,094
Regulatory Assets - Total		$ 144,252	$ 153,391
Regulatory Assets - Remaining Recovery/Refund Period (Month)
Regulatory Liabilities - Current		$ 5,203	$ 3,294
Regulatory Liabilities - Long -Term		84,281	82,433
Regulatory Liabilities		$ 89,484	85,727
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)
Net Regulatory Asset Position - Current		$ 16,379	18,003
Net Regulatory Asset Position - Long-Term		38,389	49,661
Net Regulatory Asset Position		54,768	67,664
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		82,485	80,404
Regulatory Liabilities		$ 82,485	$ 80,404
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Minnesota Transmission Cost Recovery Rider Accrued Refund [member]
Regulatory Liabilities - Current		$ 1,808	$ 757
Regulatory Liabilities - Long -Term		616
Regulatory Liabilities		$ 2,424	$ 757
Regulatory Liabilities - Remaining Recovery/Refund Period		24
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)			1 year
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 1,722	$ 139
Regulatory Liabilities - Long -Term
Regulatory Liabilities		$ 1,722	$ 139
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 716	$ 1,381
Regulatory Liabilities - Long -Term		342	782
Regulatory Liabilities		$ 1,058	$ 2,163
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 90 days	2 years
Deferred Income Taxes [Member]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		720	818
Regulatory Liabilities		$ 720	$ 818
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member]
Regulatory Liabilities - Current		$ 385	$ 711
Regulatory Liabilities - Long -Term			208
Regulatory Liabilities		$ 385	$ 919
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		210 days	1 year 120 days
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 252	$ 285
Regulatory Liabilities - Long -Term
Regulatory Liabilities		$ 252	$ 285
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year	1 year
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 172
Regulatory Liabilities - Long -Term
Regulatory Liabilities		$ 172
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Liabilities - Current		$ 99
Regulatory Liabilities - Long -Term		33	132
Regulatory Liabilities		$ 132	$ 132
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		1 year 90 days	2 years
Other [Member]
Regulatory Liabilities - Current		$ 6	$ 21
Regulatory Liabilities - Long -Term		85	89
Regulatory Liabilities		$ 91	$ 110
Regulatory Liabilities - Remaining Recovery/Refund Period (Month)		16 years 90 days	17 years
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member]
Regulatory Liabilities - Current		$ 43
Regulatory Liabilities - Long -Term
Regulatory Liabilities		$ 43
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]	$ 6,444	$ 6,443
Regulatory Assets - Long -Term	[1]	103,434	108,267
Regulatory Assets - Total	[1]	$ 109,878	$ 114,710
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Conservation Improvement Program Costs and Incentives [Member]
Regulatory Assets - Current	[2]	$ 8,230	$ 4,836
Regulatory Assets - Long -Term	[2]	2,351	5,158
Regulatory Assets - Total	[2]	$ 10,581	$ 9,994
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	2 years	1 year 270 days
Deferred Marked-to-Market Losses [Member]
Regulatory Assets - Current	[1]	$ 4,063	$ 4,063
Regulatory Assets - Long -Term	[1]	3,420	6,467
Regulatory Assets - Total	[1]	$ 7,483	$ 10,530
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	3 years 90 days	4 years
Accumulated ARO Accretion/Depreciation Adjustment [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	6,525	6,153
Regulatory Assets - Total	[1]	$ 6,525	$ 6,153
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member]
Regulatory Assets - Current	[2]	$ 88	$ 333
Regulatory Assets - Long -Term	[2]	2,432
Regulatory Assets - Total	[2]	$ 2,520	$ 333
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	2 years 90 days	1 year
Big Stone II Unrecovered Project Costs - Minnesota [Member]
Regulatory Assets - Current	[1]	$ 658	$ 778
Regulatory Assets - Long -Term	[1]	1,597	2,087
Regulatory Assets - Total	[1]	$ 2,255	$ 2,865
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	3 years 210 days	4 years 120 days
Debt Reacquisition Premiums [Member]
Regulatory Assets - Current	[1]	$ 252	$ 325
Regulatory Assets - Long -Term	[1]	1,026	1,214
Regulatory Assets - Total	[1]	$ 1,278	$ 1,539
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	15 years	15 years 270 days
Recoverable Fuel and Purchased Power Costs [Member]
Regulatory Assets - Current	[1]	$ 885	$ 1,798
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 885	$ 1,798
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	1 year	1 year
Deferred Income Taxes [Member]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	833	1,014
Regulatory Assets - Total	[1]	$ 833	$ 1,014
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
North Dakota Renewable Resource Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 189	$ 1,319
Regulatory Assets - Long -Term	[2]	585	482
Regulatory Assets - Total	[2]	$ 774	$ 1,801
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	1 year 180 days	1 year 90 days
Big Stone II Unrecovered Project Costs - South Dakota [Member]
Regulatory Assets - Current	[2]	$ 100	$ 100
Regulatory Assets - Long -Term	[2]	467	543
Regulatory Assets - Total	[2]	$ 567	$ 643
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	5 years 240 days	6 years 150 days
Minnesota Deferred Rate Case Expenses Subject to Recovery [Member]
Regulatory Assets - Current	[1]	$ 496	$ 1,082
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 496	$ 1,082
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[1]	210 days	1 year
North Dakota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 142
Regulatory Assets - Long -Term	[2]		568
Regulatory Assets - Total	[2]	$ 142	$ 568
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	90 days	2 years
South Dakota Transmission Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]	$ 35	$ 73
Regulatory Assets - Long -Term	[2]		141
Regulatory Assets - Total	[2]	$ 35	$ 214
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]	90 days	1 year 60 days
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 113
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 113
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		1 year
Minnesota Renewable Resource Rider Accrued Revenues [Member]
Regulatory Assets - Current	[2]		$ 34
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 34
Regulatory Assets - Remaining Recovery/Refund Period (Month)	[2]		270 days

[1] Costs subject to recovery without a rate of return.

[2] Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.

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Note 5 - Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Amount of Derivative Asset and Derivative Liability Balances (Details) - Legally Enforceable Netting Arrangements [Member] - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements	(13,591)	(17,382)
Net Balance Subject to Legally Enforceable Netting Arrangements	$ (13,591)	$ (17,382)

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Note 5 - Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's Credit Risk Standing (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Loss Contracts Covered by Deposited Funds or Letters of Credit
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	13,591	17,382
Total Loss Contracts based on Current Market Values		$ 13,591	$ 17,382

[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 13,591 $ 17,382 Offsetting Gains with Counterparties under Master Netting Agreements -- -- Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,591 $ 17,382

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Note 5 - Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's Credit Risk Standing (Details) (Parentheticals) - Otter Tail Power Company [Member] - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 13,591	$ 17,382
Offsetting Gains with Counterparties under Master Netting Agreements
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$ 13,591	$ 17,382

[1] Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $ 13,591 $ 17,382 Offsetting Gains with Counterparties under Master Netting Agreements -- -- Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 13,591 $ 17,382

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Note 6 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	May 11, 2015
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Distribution Agreement [Member]
Agreement to Sell Shares, Value					$ 75

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Note 6 - 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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Balance, beginning			$ 670,104
Common Stock Issuances, Net of Expenses			4,969
Common Stock Retirements			(1,799)
Net Income	$ 17,734	$ 14,616	54,097	$ 44,811
Other Comprehensive Income			341
Employee Stock Incentive Plans Expense			2,765
Common Dividends ($0.96 per share)			(37,958)
Balance, ending	692,519		692,519
Par Value, Common Shares [Member]
Balance, beginning			196,741
Common Stock Issuances, Net of Expenses			1,285
Common Stock Retirements			(239)
Net Income
Other Comprehensive Income
Employee Stock Incentive Plans Expense
Common Dividends ($0.96 per share)
Balance, ending	197,787		197,787
Premium on Common Shares [Member]
Balance, beginning			337,684
Common Stock Issuances, Net of Expenses			3,684
Common Stock Retirements			(1,560)
Net Income
Other Comprehensive Income
Employee Stock Incentive Plans Expense			2,765
Common Dividends ($0.96 per share)
Balance, ending	342,573		342,573
Retained Earnings [Member]
Balance, beginning			139,479
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income			54,097
Other Comprehensive Income
Employee Stock Incentive Plans Expense
Common Dividends ($0.96 per share)			(37,958)
Balance, ending	155,618		155,618
Accumulated Other Comprehensive Income/(Loss) [Member]
Balance, beginning			(3,800)
Common Stock Issuances, Net of Expenses
Common Stock Retirements
Net Income
Other Comprehensive Income			341
Employee Stock Incentive Plans Expense
Common Dividends ($0.96 per share)
Balance, ending	$ (3,459)		$ (3,459)

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Note 6 - 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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Dividends Declared Per Common Share (in dollars per share)	$ 0.32	$ 0.3125	$ 0.96	$ 0.9375

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Note 6 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details)	9 Months Ended
	Sep. 30, 2017 shares
Common Shares Outstanding, beginning balance (in shares)	39,348,136
Issuances:
Executive Stock Performance Awards (2014 shares earned) (in shares)	89,291
Automatic Dividend Reinvestment and Share Purchase Plan:
Dividends Reinvested (in shares)	68,235
Cash Invested (in shares)	29,463
Vesting of Restricted Stock Units (in shares)	22,225
Restricted Stock Issued to Directors (in shares)	17,600
Employee Stock Ownership Plan (in shares)	14,835
Employee Stock Purchase Plan:
Dividends Reinvested (in shares)	9,566
Cash Invested (in shares)	5,284
Directors Deferred Compensation (in shares)	560
Retirements:
Shares Withheld for Individual Income Tax Requirements (in shares)	(47,704)
Common Shares Outstanding, ending balance (in shares)	39,557,491

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Note 6 - 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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Weighted Average Common Shares Outstanding – Basic (in shares)	39,507,581	38,832,659	39,440,416	38,316,324
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)	211,996	103,084	195,869	80,450
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares)	55,975	48,645	54,645	42,620
Nonvested Restricted Shares (in shares)	16,982	18,029	18,923	14,556
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares)	2,832	3,289	3,009	3,451
Total Dilutive Shares (in shares)	287,785	173,047	272,446	141,077
Weighted Average Common Shares Outstanding – Diluted (in shares)	39,795,366	39,005,706	39,712,862	38,457,401

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Note 7 - Share-based Payments (Details Textual) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) shares
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $	$ 4.9
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 73 days
Stock Performance Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	59,500
Stock Performance Awards [Member] | Minimum [Member]
Percentage of Target Amount as Actual Payment	0.00%
Stock Performance Awards [Member] | Maximum [Member]
Percentage of Target Amount as Actual Payment	150.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	89,250
Stock Performance Awards [Member] | Executive Officer [Member]
Targeted Aggregate Common Shares Award Total Shareholder Return Component	39,667
Beginning and Ending Average Price for Measuring Total Shareholder Return	20 days
Targeted Aggregate Common Shares Award Return on Equity Component	19,833
Period Specified for Average Adjusted Return	3 years

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Note 7 - Share-based Payments - Stock Incentive Awards to Executive Officers, Key Employees and Nonemployee Directors (Details)	9 Months Ended
	Sep. 30, 2017 $ / shares shares
Stock Performance Awards [Member] | Executive Officer [Member] | Granted on February 2, 2017 [Member]
Shares/units granted, vesting date	Dec. 31, 2019
Shares/units granted (in shares) | shares	59,500
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 31
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | Granted on February 2, 2017 [Member]
Shares/units granted, vesting date	Feb. 06, 2021
Shares/units granted (in shares) | shares	15,900
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 37.65
Shares/units granted, vesting percentage	25.00%
Restricted Stock Units (RSUs) [Member] | Key Employees [Member] | Granted on April 10, 2017 [Member]
Shares/units granted, vesting date	Apr. 08, 2021
Shares/units granted (in shares) | shares	9,995
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 32.78
Shares/units granted, vesting percentage	100.00%
Restricted Stock Units (RSUs) [Member] | Key Employees [Member] | Granted on September 25, 2017 [Member]
Shares/units granted, vesting date	Apr. 08, 2021
Shares/units granted (in shares) | shares	1,000
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 38.29
Shares/units granted, vesting percentage	100.00%
Restricted Stock Units (RSUs) [Member] | Nonemployee Directors [Member] | Granted on April 10, 2017 [Member]
Shares/units granted, vesting date	Apr. 08, 2021
Shares/units granted (in shares) | shares	17,600
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares	$ 37.75
Shares/units granted, vesting percentage	25.00%

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Note 7 - 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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Stock compensation expense	$ 845	$ 778	$ 2,765	$ 2,447
Employee Stock Purchase Plan [Member]
Stock compensation expense		47		135
Stock Performance Awards [Member] | Executive Officer [Member]
Stock compensation expense	494	455	1,568	1,296
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member]
Stock compensation expense	104	64	472	373
Restricted Stock Units (RSUs) [Member] | Key Employees [Member]
Stock compensation expense	87	62	255	207
Restricted Stock [Member] | Executive Officer [Member]
Stock compensation expense	16	22	54	73
Restricted Stock [Member] | Nonemployee Directors [Member]
Stock compensation expense	$ 144	$ 128	$ 416	$ 363

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Note 7 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) (Parentheticals)	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Employee Stock Purchase Plan [Member]
Stock compensation expense, discount rate	15.00%	15.00%

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Note 8 - Retained Earnings Restriction (Details Textual) - USD ($)	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Capitalization, Long-term Debt and Equity	$ 1,182,925,000	$ 1,175,445,000
OTP [Member]
Equity to Total Capitalization Ratio	51.80%
Net Assets Restricted from Distribution	$ 462,000,000
OTP [Member] | Minimum [Member]
Equity to Total Capitalization Ratio	47.40%
OTP [Member] | Maximum [Member]
Equity to Total Capitalization Ratio	58.00%
Capitalization, Long-term Debt and Equity	$ 1,178,024,000

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Note 9 - Commitments and Contingencies (Details Textual) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)
Loss Contingency, Estimate of Possible Loss	$ 1.0
Otter Tail Power Company [Member]
Number of Utilities Participating in MISO RSG Proceeding Before FERC	200
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member]
Estimated Liability of Refund Obligation	$ 1.6	$ 2.7
Otter Tail Power Company [Member] | Construction Programs [Member]
Long-term Purchase Commitment, Amount	$ 82.6	$ 84.8
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member]
Contract Expiration Year	2040
Otter Tail Power Company [Member] | Coal Purchase Commitments [Member]
Long-term Purchase Commitment, Amount	$ 3.0
Otter Tail Power Company [Member] | Coal Purchase Commitments 1 [Member]
Contract Expiration Year	2019

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Note 10 - Short-term and Long-term Borrowings (Details Textual) - USD ($) $ in Thousands				1 Months Ended		2 Months Ended	3 Months Ended
	Aug. 21, 2017	Aug. 07, 2017	Feb. 05, 2016	Jun. 30, 2017	Jan. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Term Loan Agreement [Member]
Proceeds from Bank Debt			$ 50,000			$ 0
Debt Instrument, Basis Spread on Variable Rate			0.90%
Repayments of Debt		$ 9,000		$ 3,000	$ 3,000		$ 35,000
Debt Instrument, Interest Rate, Basis for Effective Rate			30 day LIBOR plus 90
Debt Instrument, Description of Variable Rate Basis			LIBOR
Senior Unsecured Notes 5.95%, Series A, Due August 20, 2017 [Member]
Repayments of Debt	$ 33,000

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Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Line Limit	$ 300,000
In Use	103,637
Restricted due to Outstanding Letters of Credit	300
Available	196,063	$ 257,067
Otter Tail Corporation Credit Agreement [Member]
Line Limit	130,000
In Use	1,417
Restricted due to Outstanding Letters of Credit
Available	128,583	130,000
OTP Credit Agreement [Member]
Line Limit	170,000
In Use	102,220
Restricted due to Outstanding Letters of Credit	300
Available	$ 67,480	$ 127,067

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Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Short-Term Debt	$ 103,637	$ 42,883
Long-Term Debt	492,770	540,942
Less: Current Maturities net of Unamortized Debt Issuance Costs	197	33,201
Unamortized Long-Term Debt Issuance Costs	2,167	2,400
Total Long-Term Debt net of Unamortized Debt Issuance Costs	490,406	505,341
Total Short-Term and Long-Term Debt (with current maturities)	594,240	581,425
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt		15,000
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Senior Unsecured Notes 5.95%, Series A, Due August 20, 2017 [Member]
Long-Term Debt		33,000
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [member]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt	47	106
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	723	836
OTP [Member]
Short-Term Debt	102,220	42,883
Long-Term Debt	412,000	445,000
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,970
Unamortized Long-Term Debt Issuance Costs	1,687	1,861
Total Long-Term Debt net of Unamortized Debt Issuance Costs	410,313	410,169
Total Short-Term and Long-Term Debt (with current maturities)	512,533	486,022
OTP [Member] | Senior Unsecured Notes 5.95%, Series A, Due August 20, 2017 [Member]
Long-Term Debt		33,000
OTP [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt	140,000	140,000
OTP [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt	30,000	30,000
OTP [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [member]
Long-Term Debt	42,000	42,000
OTP [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt	60,000	60,000
OTP [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt	50,000	50,000
OTP [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt	90,000	90,000
Otter Tail Corporation [Member]
Short-Term Debt	1,417
Long-Term Debt	80,770	95,942
Less: Current Maturities net of Unamortized Debt Issuance Costs	197	231
Unamortized Long-Term Debt Issuance Costs	480	539
Total Long-Term Debt net of Unamortized Debt Issuance Costs	80,093	95,172
Total Short-Term and Long-Term Debt (with current maturities)	81,707	95,403
Otter Tail Corporation [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt		15,000
Otter Tail Corporation [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt	80,000	80,000
Otter Tail Corporation [Member] | North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt	47	106
Otter Tail Corporation [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt	$ 723	$ 836

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Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals)	9 Months Ended
	Sep. 30, 2017
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member]
Long-Term Debt, Interest Rate	0.90%
Long-Term Debt, Due Date	Feb. 05, 2018
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member]
Long-Term Debt, Interest Rate	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member]
Long-Term Debt, Interest Rate	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member]
Long-Term Debt, Interest Rate	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [member]
Long-Term Debt, Interest Rate	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member]
Long-Term Debt, Interest Rate	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member]
Long-Term Debt, Interest Rate	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member]
Long-Term Debt, Interest Rate	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044
North Dakota Development Note, 3.95%, Due April 1, 2018 [member]
Long-Term Debt, Interest Rate	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member]
Long-Term Debt, Interest Rate	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021

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Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual)	1 Months Ended
	Jan. 31, 2016 USD ($)
Pension Plan [Member]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 10,000,000

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Note 11 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Pension Benefit Cost (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plan [Member]
Service Cost—Benefit Earned During the Period		$ 1,407	$ 1,376	$ 4,221	$ 4,139
Interest Cost on Projected Benefit Obligation		3,534	3,603	10,604	10,646
Expected Return on Assets		(4,807)	(4,857)	(14,421)	(14,590)
Amortization of Prior-Service Cost:
From Regulatory Asset		30	48	89	142
From Other Comprehensive Income	[1]	1	1	3	3
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273	1,411	3,818	3,865
From Other Comprehensive Income	[1]	31	32	94	95
Net Periodic Pension Cost		1,469	1,614	4,408	4,300
Executive Survivor and Supplemental Retirement Plan [Member]
Service Cost—Benefit Earned During the Period		73	63	218	189
Interest Cost on Projected Benefit Obligation		421	417	1,264	1,251
Amortization of Prior-Service Cost:
From Regulatory Asset		4	4	12	12
From Other Comprehensive Income	[2]	10	9	29	28
Amortization of Net Actuarial Loss:
From Regulatory Asset		70	74	213	220
From Other Comprehensive Income	[3]	110	111	330	334
Net Periodic Pension Cost		688	678	2,066	2,034
Postretirement Benefits [Member]
Service Cost—Benefit Earned During the Period		357	365	1,069	976
Interest Cost on Projected Benefit Obligation		678	794	2,034	1,877
Amortization of Prior-Service Cost:
From Regulatory Asset			34		100
From Other Comprehensive Income	[1]		1		3
Amortization of Net Actuarial Loss:
From Regulatory Asset		233	284	699	284
From Other Comprehensive Income	[1]	5	7	17	7
Net Periodic Pension Cost		1,273	1,485	3,819	3,247
Effect of Medicare Part D Subsidy		$ (141)	$ (177)	$ (421)	$ (692)

[1] Corporate cost included in Other Nonelectric Expenses.

[2] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 3 $ 12 $ 11 Other Nonelectric Expenses 6 6 17 17

[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 67 $ 68 $ 199 $ 204 Other Nonelectric Expenses 43 43 131 130

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Note 11 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Pension Benefit Cost (Details) (Parentheticals) - Executive Survivor and Supplemental Retirement Plan [Member] - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:	[1]	$ 10	$ 9	$ 29	$ 28
Amortization of Net Actuarial Loss from Other Comprehensive Income Charge to:	[2]	110	111	330	334
Electric Operation and Maintenance Expenses [Member]
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:		4	3	12	11
Amortization of Net Actuarial Loss from Other Comprehensive Income Charge to:		67	68	199	204
Other Nonelectric Expenses [member]
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:		6	6	17	17
Amortization of Net Actuarial Loss from Other Comprehensive Income Charge to:		$ 43	$ 43	$ 131	$ 130

[1] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 3 $ 12 $ 11 Other Nonelectric Expenses 6 6 17 17

[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 67 $ 68 $ 199 $ 204 Other Nonelectric Expenses 43 43 131 130

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Note 12 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member]	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Otter Tail Corporation Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.75%	1.75%
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR
OTP Credit Agreement [Member]
Debt Instrument, Basis Spread on Variable Rate	1.25%	1.25%
Debt Instrument, Description of Variable Rate Basis	LIBOR	LIBOR

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Note 12 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Reported Value Measurement [Member]
Cash and Cash Equivalents	$ 826
Short-Term Debt	(103,637)	(42,883)
Long-Term Debt including Current Maturities	(490,603)	(538,542)
Estimate of Fair Value Measurement [Member]
Cash and Cash Equivalents	826
Short-Term Debt	(103,637)	(42,883)
Long-Term Debt including Current Maturities	$ (543,870)	$ (583,835)

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Note 14 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Before Income Taxes – Continuing Operations	$ 24,808	$ 19,757	$ 73,314	$ 60,378
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)	9,675	7,705	28,592	23,547
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(1,349)	(1,423)	(5,411)	(4,994)
Section 199 Domestic Production Activities Deduction	(330)	(9)	(990)	(207)
Excess Tax Deduction – 2014 Performance Share Awards			(697)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes	(212)	(212)	(637)	(637)
Corporate-Owned Life Insurance	(118)	(92)	(620)	(664)
Employee Stock Ownership Plan Dividend Deduction	(172)	(157)	(517)	(472)
R&D Tax Credits	(148)	(223)	(454)	(445)
Investment Tax Credits	(41)	(87)	(122)	(262)
Other Items – Net	(270)	(339)	151	(128)
Income Tax Expense—Continuing Operations	$ 7,035	$ 5,163	$ 19,295	$ 15,738
Effective Income Tax Rate – Continuing Operations	28.40%	26.10%	26.30%	26.10%

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Note 14 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Composite Federal and State Statutory Rate	39.00%	39.00%	39.00%	39.00%

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Note 14 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Balance on January 1	$ 891	$ 468
Increases Related to Tax Positions for Prior Years	28	40
Increases Related to Tax Positions for Current Year	220	26
Uncertain Positions Resolved During Year	(206)	(97)
Balance on September 30	$ 933	$ 437

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Note 16 - Discontinued Operations (Details Textual)	9 Months Ended
	Sep. 30, 2017
Maximum [Member]
Standard Product Warranty Term	15 years

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Note 16 - Discontinued Operations - Schedule of Warranty Reserves (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Balance, January 1	$ 1,369	$ 2,103
Additional Provision for Warranties Made During the Year
Settlements Made During the Year	(112)	(24)
Decrease in Warranty Estimates for Prior Years	(400)	(530)
Balance, June 30	$ 857	$ 1,549