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 March 31, 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  þ     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  þ       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 þ	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 þ   No ¨

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

April 30, 2017 – 39,503,539 Common Shares ($5 par value)

OTTER TAIL CORPORATION

INDEX

		Page No.
Part I.   Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets – March 31, 2017 and December 31, 2016 (not audited)	2 & 3
	Consolidated Statements of Income - Three Months Ended March 31, 2017 and 2016 (not audited)	4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2017 and 2016 (not audited)	5
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2017 and 2016 (not audited)	6
	Condensed Notes to Consolidated Financial Statements (not audited)	7-29
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29-42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42-43
Item 4.	Controls and Procedures	43
Part II.  Other Information
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 6.	Exhibits	44
Signatures		44

1 

PART I. FINANCIAL INFORMATION

Item 1. financial statements

Otter Tail Corporation

Consolidated Balance Sheets

(not audited)

(in thousands)	March 31, 2017		December 31, 2016
Assets
Current Assets
Cash and Cash Equivalents	$	—	$	—
Accounts Receivable:
Trade—Net		82,369		68,242
Other		7,244		5,850
Inventories		81,473		83,740
Unbilled Revenues		18,016		20,080
Income Taxes Receivable		—		662
Regulatory Assets		17,973		21,297
Other		11,837		8,144
Total Current Assets		218,912		208,015
Investments		8,125		8,417
Other Assets		35,416		34,104
Goodwill		37,572		37,572
Other Intangibles—Net		14,626		14,958
Regulatory Assets		128,968		132,094
Plant
Electric Plant in Service		1,868,689		1,860,357
Nonelectric Operations		212,976		211,826
Construction Work in Progress		166,866		153,261
Total Gross Plant		2,248,531		2,225,444
Less Accumulated Depreciation and Amortization		761,444		748,219
Net Plant		1,487,087		1,477,225
Total Assets	$	1,930,706	$	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)	March 31, 2017			December 31, 2016
Liabilities and Equity
Current Liabilities
Short-Term Debt	$	59,176		$	42,883
Current Maturities of Long-Term Debt		45,192			33,201
Accounts Payable		83,622			89,350
Accrued Salaries and Wages		12,957			17,497
Accrued Federal and State Income Taxes		1,107			—
Other Accrued Taxes		17,068			16,000
Other Accrued Liabilities		15,584			15,377
Liabilities of Discontinued Operations		1,268			1,363
Total Current Liabilities		235,974			215,671
Pensions Benefit Liability		97,962			97,627
Other Postretirement Benefits Liability		62,796			62,571
Other Noncurrent Liabilities		22,168			21,706
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes		231,210			226,591
Deferred Tax Credits		22,483			22,849
Regulatory Liabilities		82,316			82,433
Other		6,302			7,492
Total Deferred Credits		342,311			339,365
Capitalization
Long-Term Debt—Net		490,372			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—39,468,804 Shares; 2016—39,348,136 Shares		197,344			196,741
Premium on Common Shares		339,036			337,684
Retained Earnings		146,438			139,479
Accumulated Other Comprehensive Loss		(3,695	)		(3,800	)
Total Common Equity		679,123			670,104
Total Capitalization		1,169,495			1,175,445
Total Liabilities and Equity	$	1,930,706		$	1,912,385

See accompanying condensed notes to consolidated financial statements.

3 

Otter Tail Corporation

Consolidated Statements of Income

(not audited)

	Three Months Ended March 31,
(in thousands, except share and per-share amounts)	2017		2016
Operating Revenues
Electric	$	118,543	$	112,985
Product Sales		95,574		93,257
Total Operating Revenues		214,117		206,242
Operating Expenses
Production Fuel - Electric		16,382		15,700
Purchased Power - Electric		19,188		16,886
Electric Operation and Maintenance Expenses		38,379		40,018
Cost of Products Sold (depreciation included below)		75,277		72,639
Other Nonelectric Expenses		10,438		11,455
Depreciation and Amortization		17,854		18,289
Property Taxes - Electric		3,798		3,679
Total Operating Expenses		181,316		178,666
Operating Income		32,801		27,576
Interest Charges		7,462		7,994
Other Income		553		400
Income Before Income Taxes – Continuing Operations		25,892		19,982
Income Tax Expense – Continuing Operations		6,363		5,492
Net Income from Continuing Operations		19,529		14,490
Income from Discontinued Operations - net of Income Tax Expense of $38 in 2017 and $20 in 2016		56		30
Net Income		19,585		14,520
Average Number of Common Shares Outstanding—Basic		39,350,802		37,936,943
Average Number of Common Shares Outstanding—Diluted		39,640,725		38,045,208
Basic Earnings Per Common Share:
Continuing Operations	$	0.50	$	0.38
Discontinued Operations		—		—
	$	0.50	$	0.38
Diluted Earnings Per Common Share:
Continuing Operations	$	0.49	$	0.38
Discontinued Operations		—		—
	$	0.49	$	0.38
Dividends Declared Per Common Share	$	0.3200	$	0.3125

See accompanying condensed notes to consolidated financial statements

4 

Otter Tail Corporation

 Consolidated Statements of Comprehensive Income

(not audited)

	Three Months Ended March 31,
(in thousands)	2017			2016
Net Income	$	19,585		$	14,520
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Gains Arising During Period		17			73
Income Tax Expense		(6	)		(26	)
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax		11			47
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)		157			154
Income Tax Expense		(63	)		(61	)
Pension and Postretirement Benefit Plans – net-of-tax		94			93
Total Other Comprehensive Income		105			140
Total Comprehensive Income	$	19,690		$	14,660

See accompanying condensed notes to consolidated financial statements.

5 

Otter Tail Corporation

Consolidated Statements of Cash Flows

(not audited)

	Three Months Ended March 31,
(in thousands)	2017			2016
Cash Flows from Operating Activities
Net Income	$	19,585		$	14,520
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations		(56	)		(30	)
Depreciation and Amortization		17,854			18,289
Deferred Tax Credits		(366	)		(414	)
Deferred Income Taxes		4,512			5,330
Change in Deferred Debits and Other Assets		5,005			2,825
Discretionary Contribution to Pension Plan		—			(10,000	)
Change in Noncurrent Liabilities and Deferred Credits		1,314			3,363
Allowance for Equity/Other Funds Used During Construction		(170	)		(95	)
Stock Compensation Expense—Equity Awards		1,150			489
Other—Net		(5	)		15
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables		(15,521	)		(7,478	)
Change in Inventories		2,267			6
Change in Other Current Assets		(22	)		(773	)
Change in Payables and Other Current Liabilities		(13,986	)		(5,840	)
Change in Interest and Income Taxes Receivable/Payable		(321	)		2,400
Net Cash Provided by Continuing Operations		21,240			22,607
Net Cash (Used in) Provided by Discontinued Operations		(39	)		30
Net Cash Provided by Operating Activities		21,201			22,637
Cash Flows from Investing Activities
Capital Expenditures		(30,113	)		(24,855	)
Net Proceeds from Disposal of Noncurrent Assets		612			682
Cash Used for Investments and Other Assets		(508	)		(1,425	)
Net Cash Used in Investing Activities		(30,009	)		(25,598	)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash		7,999			(666	)
Net Short-Term Borrowings (Repayments)		16,293			(37,736	)
Proceeds from Issuance of Common Stock – net of Issuance Expenses		1,958			3,415
Payments for Retirement of Capital Stock		(1,759	)		(53	)
Proceeds from Issuance of Long-Term Debt		—			50,000
Short-Term and Long-Term Debt Issuance Expenses		—			(58	)
Payments for Retirement of Long-Term Debt		(3,057	)		(52	)
Dividends Paid		(12,626	)		(11,889	)
Net Cash Provided by Financing Activities		8,808			2,961
Net Change in Cash and Cash Equivalents		—			—
Cash and Cash Equivalents at Beginning of Period		—			—
Cash and Cash Equivalents at End of Period	$	—		$	—

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 months ended March 31, 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 product. 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,590
Government-Backed and Government-Sponsored  Enterprises’ Debt Securities – Held by Captive Insurance Company				2,345
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	828
Total Assets	$	828	$	7,935

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 March 31, 2017 could be as high as $59.7 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:

	March 31,		December 31,
(in thousands)	2017		2016
Finished Goods	$	24,018	$	27,755
Work in Process		12,801		11,754
Raw Material, Fuel and Supplies		44,654		44,231
Total Inventories	$	81,473	$	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 three 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) March 31, 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,144	$	14,347	33-221 months
Covenant not to Compete		590		311		279	17 months
Total	$	23,081	$	8,455	$	14,626
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36-224 months
Covenant not to Compete		590		262		328	20 months
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Amortization Expense – Intangible Assets	$	332	$	357

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	$	1,330	$	1,264	$	1,133	$	1,099	$	1,099

9 

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2017		2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,811	$	24,618

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 is 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. As of March 31, 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 evaluating transition options. 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 treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice. 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. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

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, developing a list of all current leases outstanding and identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and 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.

10 

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 what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated income statements upon adoption of the amendments in ASU 2017-07. 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 material and handling trays and horticultural containers. 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 98.4% and 97.6% of its operating revenues for the respective three month periods ended March 31, 2017 and 2016 came from sales within the United States.

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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 months ended March 31, 2017 and 2016 and total assets by business segment as of March 31, 2017 and December 31, 2016 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	118,551		$	112,994
Manufacturing		58,417			59,820
Plastics		37,157			33,437
Intersegment Eliminations		(8	)		(9	)
Total	$	214,117		$	206,242

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Electric	$	6,386	$	6,284
Manufacturing		554		992
Plastics		153		244
Corporate and Intersegment Eliminations		369		474
Total	$	7,462	$	7,994

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	6,062		$	4,612
Manufacturing		1,055			1,019
Plastics		1,390			1,367
Corporate		(2,144	)		(1,506	)
Total	$	6,363		$	5,492

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	15,560		$	12,538
Manufacturing		2,172			1,853
Plastics		2,437			2,152
Corporate		(640	)		(2,053	)
Discontinued Operations		56			30
Total	$	19,585		$	14,520

Identifiable Assets

	March 31,		December 31,
(in thousands)	2017		2016
Electric	$	1,630,071	$	1,622,231
Manufacturing		170,805		166,525
Plastics		91,049		84,592
Corporate		38,781		39,037
Total	$	1,930,706	$	1,912,385

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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

The Big Stone South – Brookings Multi-Value Transmission Project (MVP) and Capacity Expansion 2020 (CapX2020) Project—This 345 kiloVolt (kV) transmission line, currently under construction, will extend 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 (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project 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 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 is expected to be in service in fall 2017. OTP’s capitalized costs on this project as of March 31, 2017 were approximately $64.0 million, which includes assets that are 100% owned by OTP.

The 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. (MDU), 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 March 31, 2017 were approximately $57.9 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—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information is detailed in the table below:

($ in thousands)	Annualized or Test Year			Actual Through March 31, 2017
Revenue Increase Requested	$	19,296
Increase Percentage Requested		9.80	%
Jurisdictional Rate Base	$	483,000
Interim Revenue Increase (subject to refund)	$	16,816		$	15,335

The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity.

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Oral arguments before the MPUC occurred February 23, 2017 with deliberations on March 2, 2017. The MPUC rendered its final decision in March 2017 and issued its written order on May 1, 2017. The MPUC authorized a revenue increase of approximately $12.3 million through a 6.27% increase in base rate revenues compared to the authorized interim rate increase of 9.56%. The MPUC’s written order included: (1) an allowed rate of return on equity of 9.41%, (2) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South to Brookings and Big Stone South to Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (3) 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 at the time final rates are implemented at the end of this rate case. 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. 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%. OTP's rate of return will be based on a capital structure of 47.50% long term debt and 52.50% common equity. Parties may request clarification or reconsideration of the MPUC’s rulings consistent with Minnesota law. Based on the MPUC deliberations regarding OTP’s 2016 revenue increase request, OTP had recorded an estimated interim rate refund of $5.2 million, including interest, as of March 31, 2017.

2010 General Rate Case—A general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.

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 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 requested for 2016, $4.3 million approved for 2015 and $3.0 million approved for 2014. The MNDOC recently granted two large customers’ requests for exemption from OTP’s MNCIP pursuant to Minnesota Law. With the exemption of these two customers, recovery of the portion of OTP’s MNCIP costs previously recovered from these two customers has shifted to OTP’s other Minnesota customers.

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, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s share of 100% 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, despite an ALJ recommendation that the MPUC affirm OTP’s proposed treatment. The MPUC ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes.

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.

North Dakota

General Rates—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 the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. 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.

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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. 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 Mercury and Air Toxics Standards (MATS) projects.

Rate Rider Updates

The following table provides summary information on the status of updates for the previous two years for the various 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	R – March 31, 2017	October 1, 2017	$	9,868	$0.00754/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
2016 Annual Update1	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
2016 Annual Update1	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
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	R – March 31, 2017	July 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
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 and subject to change based on comments from the MNDOC.

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Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31:

Rate Rider (in thousands)	2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,966	$	2,506
Transmission Cost Recovery		2,170		2,276
Environmental Cost Recovery		2,824		3,082
North Dakota
Renewable Resource Adjustment		1,770		2,059
Transmission Cost Recovery		2,511		2,236
Environmental Cost Recovery		2,488		2,811
South Dakota
Transmission Cost Recovery		441		651
Environmental Cost Recovery		597		633
Conservation Improvement Program Costs and Incentives		240		159

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 of 1935, as amended. 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 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%.

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%. A lack of a quorum at FERC will delay the issuance of an order in the second complaint for an uncertain period of time.

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 90% of the FERC ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period in its February 2017 billings. 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 on December 31, 2016 to $1.7 million as of March 31, 2017.

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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:

	March 31, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,443	$	106,656	$	113,099	see below
Deferred Marked-to-Market Losses1		4,063		5,452		9,515	45 months
Conservation Improvement Program Costs and Incentives2		3,745		5,735		9,480	30 months
Accumulated ARO Accretion/Depreciation Adjustment1		—		6,276		6,276	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		739		1,926		2,665	49 months
Debt Reacquisition Premiums1		301		1,150		1,451	186 months
Deferred Income Taxes1		—		1,020		1,020	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery1		954		—		954	12 months
North Dakota Renewable Resource Rider Accrued Revenues2		727		62		789	24 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		517		617	74 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		426		59		485	21 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		251		115		366	21 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		106		—		106	11 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		95		—		95	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		23		—		23	6 months
Total Regulatory Assets	$	17,973	$	128,968	$	146,941
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	81,314	$	81,314	asset lives
Refundable Fuel Clause Adjustment Revenues		2,119		—		2,119	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,545		—		1,545	12 months
Deferred Income Taxes		—		785		785	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		30		741	13 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		631		—		631	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		354		—		354	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		299		—		299	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		33		99		132	21 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		8		—		8	12 months
Other		6		88		94	201 months
Total Regulatory Liabilities	$	5,706	$	82,316	$	88,022
Net Regulatory Asset Position	$	12,267	$	46,652	$	58,919

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
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,443	$	108,267	$	114,710	see below
Deferred Marked-to-Market Losses1		4,063		6,467		10,530	48 months
Conservation Improvement Program Costs and Incentives2		4,836		5,158		9,994	21 months
Accumulated ARO Accretion/Depreciation Adjustment1		—		6,153		6,153	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		778		2,087		2,865	52 months
Recoverable Fuel and Purchased Power Costs1		1,798		—		1,798	12 months
Debt Reacquisition Premiums1		325		1,214		1,539	189 months
Deferred Income Taxes1		—		1,014		1,014	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery1		1,082		—		1,082	12 months
North Dakota Renewable Resource Rider Accrued Revenues2		1,319		482		1,801	15 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		543		643	77 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		—		568		568	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		333		—		333	12 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		73		141		214	14 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues2		113		—		113	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		34		—		34	9 months
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
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,381		782		2,163	24 months
Deferred Income Taxes		—		818		818	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		208		919	16 months
Minnesota Transmission Cost Recovery Rider Accrued Refund		757		—		757	12 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		139		—		139	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		285		—		285	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		—		132		132	24 months
Other		21		89		110	204 months
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.

All Deferred Marked-to-Market Losses recorded as of March 31, 2017 relate to forward purchases of energy scheduled for delivery through December 2020.

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

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

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 186 months.

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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.

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.

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 March 31, 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.

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 March 31, 2017.

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.

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 March 31, 2017.

The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 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 North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 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 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 March 31, 2017.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 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 March 31, 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 March 31, 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 March 31, 2017 and December 31, 2016:

(in thousands)	March 31, 2017			December 31, 2016
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	—		$	—
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(14,590	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(14,590	)	$	(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 March 31, 2017 and December 31, 2016:

(in thousands)	March 31, 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		14,590		17,382
Total Loss Contracts based on Current Market Values	$	14,590	$	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	$	14,590	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		—		—
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	14,590	$	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		837			1,727									2,564
Common Stock Retirements		(234	)		(1,525	)								(1,759	)
Net Income								19,585						19,585
Other Comprehensive Income											105			105
Employee Stock Incentive Plans Expense					1,150									1,150
Common Dividends ($0.32 per share)								(12,626	)					(12,626	)
Balance, March 31, 2017	$	197,344		$	339,036		$	146,438		$	(3,695	)	$	679,123

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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 March 31, 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	36,320
Cash Invested	11,750
Employee Stock Ownership Plan	14,835
Vesting of Restricted Stock Units	9,975
Employee Stock Purchase Plan:
Cash Invested	—
Dividends Reinvested	5,131
Retirements:
Shares Withheld for Individual Income Tax Requirements	(46,634	)
Common Shares Outstanding, March 31, 2017	39,468,804

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 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 for the three month periods ended March 31:

	2017		2016
Weighted Average Common Shares Outstanding – Basic		39,350,802		37,936,943
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		201,639		46,885
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		57,873		39,841
Nonvested Restricted Shares		27,069		17,776
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,342		3,763
Total Dilutive Shares		289,923		108,265
Weighted Average Common Shares Outstanding – Diluted		39,640,725		38,045,208

The effect of dilutive shares on earnings per share for the three month periods ended March 31, 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

On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,900	$	37.65	25% per year through February 6, 2021
Stock Performance Awards Granted		59,500	$	31.00	December 31, 2019

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 was the average of the high and low market price per share on the date of grant.

Under the performance share awards, the aggregate award for performance at target is 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 return on equity. 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 terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award.

Under the 2017 Performance Award Agreements, payment and 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 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 March 31, 2017 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.3 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2017 and 2016 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2017		2016
Stock Performance Awards Granted to Executive Officers	$	649	$	537
Restricted Stock Units Granted to Executive Officers		264		245
Restricted Stock Granted to Executive Officers		22		29
Restricted Stock Granted to Directors		128		107
Restricted Stock Units Granted to Non-Executive Employees		87		64
Employee Stock Purchase Plan (15% discount)		—		44
Totals	$	1,150	$	1,026

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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 March 31, 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 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. As of March 31, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $443,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000.

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $84.8 million. At March 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $114.6 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 OTP rolled forward a portion of its coal supply for Big Stone Plant that it expected to take delivery of in 2016 into 2018 and entered into an agreement to purchase additional tons in 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 for the period of January 1, 2016 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 2017 MISO billings MISO processed the refund of 90% 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 $1.7 million as of March 31, 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

24 

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 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. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. The parties have been unable to settle the issues on appeal and the cases will likely revert to the active calendar of the D.C. Circuit. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, 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. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse 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 proposed standards of performance for carbon dioxide (CO₂) emissions from new, reconstructed and modified fossil fuel-fired power plants 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. All of these rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. 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 and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. 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 has now issued orders holding in abeyance both the appeals on new, reconstructed and modified fossil fuel-fired power plants and the Clean Power Plan, pending EPA review. Therefore, while the Clean Power Plan remains stayed, there is uncertainty regarding its future, and each of the CO₂ rules could change, at least to some extent, through future agency action.

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2017 will not be material.

10. Short-Term and Long-Term Borrowings

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

(in thousands)	Line Limit		In Use on March 31, 2017		Restricted due to Outstanding Letters of Credit		Available on March 31, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	12,825	$	—	$	117,175	$	130,000
OTP Credit Agreement		170,000		46,351		50		123,599		127,067
Total	$	300,000	$	59,176	$	50	$	240,774	$	257,067

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 repaid an additional $3.0 million in the first quarter of 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	46,351	$	12,825	$	59,176
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	12,000	$	12,000
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				86		86
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				799		799
Total	$	445,000	$	92,885	$	537,885
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,981		12,211		45,192
Unamortized Long-Term Debt Issuance Costs		1,801		520		2,321
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,218	$	80,154	$	490,372
Total Short-Term and Long-Term Debt (with current maturities)	$	489,550	$	105,190	$	594,740

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 March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	1,407		$	1,382
Interest Cost on Projected Benefit Obligation		3,534			3,522
Expected Return on Assets		(4,807	)		(4,867	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			47
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,227
From Other Comprehensive Income1		31			31
Net Periodic Pension Cost	$	1,469		$	1,343
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 March 31,
(in thousands)	2017		2016
Service Cost—Benefit Earned During the Period	$	73	$	63
Interest Cost on Projected Benefit Obligation		422		417
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income1		9		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		71		73
From Other Comprehensive Income2		110		112
Net Periodic Pension Cost	$	689	$	678
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	4
Other Nonelectric Expenses		5		5
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	66	$	68
Other Nonelectric Expenses		44		44

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 March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	356		$	306
Interest Cost on Projected Benefit Obligation		678			541
Amortization of Prior-Service Costs:
From Regulatory Asset		—			33
From Other Comprehensive Income1		—			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			—
From Other Comprehensive Income1		6			—
Net Periodic Postretirement Benefit Cost	$	1,273		$	881
Effect of Medicare Part D Subsidy	$	(140	)	$	(257	)
1 Corporate 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:

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 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.

	March 31, 2017						December 31, 2016
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Short-Term Debt		(59,176	)		(59,176	)		(42,883	)		(42,883	)
Long-Term Debt including Current Maturities		(535,564	)		(582,743	)		(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 for the three month periods ended March 31, 2017 and 2016:

	Three Months Ended March 31,
(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	25,892		$	19,982
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		10,098			7,793
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,052	)		(1,686	)
Excess Tax Deduction – 2014 Performance Share Awards		(697	)		—
Section 199 Domestic Production Activities Deduction		(330	)		(104	)
Corporate Owned Life Insurance		(294	)		(92	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(158	)
Other Items – Net		22			(49	)
Income Tax Expense – Continuing Operations	$	6,363		$	5,492
Effective Income Tax Rate – Continuing Operations		24.6	%		27.5	%

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		—		—
Increases Related to Tax Positions for Current Year		43		16
Uncertain Positions Resolved During Year		—		—
Balance on March 31	$	934	$	484

The balance of unrecognized tax benefits as of March 31, 2017 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 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 March 31, 2017.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of March 31, 2017, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes.

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16. Discontinued Operations

Included in discontinued operations are activities related to the Company’s former wind tower manufacturing business and dock and boatlift company. 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		(1	)		—
Decrease in Warranty Estimates for Prior Years		(100	)		—
Warranty Reserve Balance, March 31	$	1,268		$	2,103

The warranty reserve balances as of March 31, 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 one to 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.

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 months ended March 31, 2017 and 2016, followed by a discussion of changes in our consolidated financial position during the three months ended March 31, 2017 and our business outlook for the remainder of 2017.

Comparison of the Three Months Ended March 31, 2017 and 2016

Consolidated operating revenues were $214.1 million for the three months ended March 31, 2017 compared with $206.2 million for the three months ended March 31, 2016. Operating income was $32.8 million for the three months ended March 31, 2017 compared with $27.6 million for the three months ended March 31, 2016. The Company recorded diluted earnings per share from continuing operations of $0.49 for the three months ended March 31, 2017 compared with $0.38 for the three months ended March 31, 2016, and total diluted earnings per share of $0.49 for the three months ended March 31, 2017 compared with $0.38 for the three months ended March 31, 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 March 31, 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)	March 31, 2017		March 31, 2016
Operating Revenues:
Electric	$	8	$	9
Nonelectric		—		—
Costs of Products Sold		1		—
Other Nonelectric Expenses		7		9

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Electric

	Three Months Ended
	March 31,							%
(in thousands)	2017		2016		Change			Change
Retail Sales Revenues	$	105,215	$	100,655	$	4,560			4.5
Wholesale Revenues – Company Generation		867		911		(44	)		(4.8	)
Other Revenues		12,469		11,428		1,041			9.1
Total Operating Revenues	$	118,551	$	112,994	$	5,557			4.9
Production Fuel		16,382		15,700		682			4.3
Purchased Power – System Use		19,188		16,886		2,302			13.6
Other Operation and Maintenance Expenses		38,379		40,018		(1,639	)		(4.1	)
Depreciation and Amortization		13,066		13,483		(417	)		(3.1	)
Property Taxes		3,798		3,679		119			3.2
Operating Income	$	27,738	$	23,228	$	4,510			19.4
Electric kilowatt-hour (kwh) Sales (in thousands)
Retail kwh Sales		1,389,921		1,373,199		16,722			1.2
Wholesale kwh Sales – Company Generation		38,934		43,410		(4,476	)		(10.3	)
Heating Degree Days		3,082		2,799		283			10.1

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

	Three Months ended March 31,
	2017		2016
Heating Degree Days		90.1%		81.8%

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 quarters of 2017 and 2016 and between the quarters:

	2017 vs Normal			2016 vs Normal			2017 vs 2016
Effect on Diluted Earnings Per Share	$	(0.02	)	$	(0.04	)	$	0.02

The $4.6 million increase in retail revenue includes:

· A $3.0 million increase in retail revenue related to the recovery of increased fuel and purchased power costs due to a 10.1% increase in the price per kwh purchased and a 3.7% increase in fuel costs per kwh generated to serve retail customers.

· A $2.8 million increase in retail revenue, net of an estimated refund, related to an interim rate increase implemented in mid-April 2016 in conjunction with Otter Tail Power Company's (OTP’s) 2016 general rate increase request in Minnesota.

· A $1.2 million increase in revenues related to increased consumption due to colder weather in the first quarter of 2017, evidenced by a 10.1% increase in heating degree days between the quarters.

offset by:

· A $1.1 million reduction in revenues related to lower prices on industrial kwh sales due to a pipeline customer opting for market-based pricing in July 2016 in combination with a 7.7% decrease in kwh sales to all industrial customers.

· A $0.6 million decrease in Environmental Cost Recovery rider revenue mainly due to a reduction in the investment balance of environmental upgrades due to depreciation.

· A $0.4 million decrease in Conservation Improvement Program (CIP) cost recovery and incentive revenues as a result of program changes made by the Minnesota Department of Commerce (MNDOC).

· A $0.3 million decrease in North Dakota Renewable Resource Adjustment rider revenues due to a lower allowed return on investment combined with a reduction in the investment balance of renewable generation assets due to depreciation.

Other electric revenues increased $1.0 million as a result of an increase in Midcontinent Independent System Operator, Inc. (MISO) transmission tariff revenues related to increased investment in regional transmission lines and an increase in interconnection revenues related to another generator's new wind project that began generating electricity in November 2016.

30 

Production fuel costs increased $0.7 million as a result of a 7.3% increase in the cost of fuel per kwh generated from our steam-powered and combustion turbine generators mainly due to an increase in fuel costs at Coyote station which began taking coal under a new supply agreement in May 2016. The increase in fuel costs per kwh of generation was partially offset by a 2.7% reduction in kwhs generated from our fuel burning plants. Hoot Lake Plant generated fewer kwhs in the first quarter of 2017 compared to the first quarter of 2016 due to lower dispatch prices from other generators.

The cost of purchased power to serve retail customers increased $2.3 million due to a 10.1% increase in the cost per kwh purchased combined with a 3.2% increase in kwhs purchased to serve retail customers. The increased cost per kwh purchased was driven by higher market demand resulting from colder weather in March 2017 compared to March 2016.

Electric operating and maintenance expenses decreased $1.6 million as a result of:

· A $1.0 million decrease in MISO transmission service charges, mainly due to a refund received in February 2017 related to a reduction in the return on equity component of the MISO tariff imposed from November 2013 through January 2015. The benefits of this refund will be passed back to retail ratepayers through state transmission cost recovery rider adjustments.

· A $0.8 million reduction in transmission and distribution line maintenance expenses, mainly for tree-trimming.

· A $0.3 million reduction in power plant maintenance expenses related to costs incurred in conjunction with a planned maintenance outage at Coyote Station in March 2016.

offset by:

· A $0.5 million increase in postemployment benefit costs.

Depreciation expense decreased $0.2 million as a result of extending the depreciable lives of certain assets and $0.2 million as a result of other assets reaching the end of their depreciable lives in 2016.

Manufacturing

	Three Months Ended
	March 31,							%
(in thousands)	2017		2016		Change			Change
Operating Revenues	$	58,417	$	59,820	$	(1,403	)		(2.3	)
Cost of Products Sold		45,028		46,055		(1,027	)		(2.2	)
Operating Expenses		5,776		6,074		(298	)		(4.9	)
Depreciation and Amortization		3,857		3,836		21			0.5
Operating Income	$	3,756	$	3,855	$	(99	)		(2.6	)

The $1.4 million decrease in revenues in our Manufacturing segment includes the following:

· Revenues at BTD Manufacturing, Inc. (BTD) decreased $2.2 million as a result of a $2.3 million reduction in sales of transportation fixtures for wind turbine blades and a $0.7 million decrease in tooling and other parts sales, offset by a $0.8 million increase in revenue from scrap metal sales mainly due to 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 a $0.5 million increase in sales of horticultural containers and a $0.2 million increase in sales of life sciences products. The increase in revenue from horticultural sales was driven by unit volume growth of 30% offset by lower product selling prices. Realized pricing for horticulture products was impacted by increased competition in the marketplace. Lower average selling prices in horticulture markets without a corresponding reduction in product cost resulted in reduced margins on sales of these products and an increase in gross profits of $0.1 million.

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

· Cost of products sold at BTD decreased $1.7 million in relationship to the decreases in sales.

· Cost of products sold at T.O. Plastics increased $0.6 million related to the increase in product sales.

The $0.3 million decrease in operating expenses in our Manufacturing segment is primarily due to a decrease in contracted services and employee benefit expenses at BTD.

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Plastics

	Three Months Ended
	March 31,							%
(in thousands)	2017		2016		Change			Change
Operating Revenues	$	37,157	$	33,437	$	3,720			11.1
Cost of Products Sold		30,250		26,584		3,666			13.8
Operating Expenses		2,028		2,148		(120	)		(5.6	)
Depreciation and Amortization		923		958		(35	)		(3.7	)
Operating Income	$	3,956	$	3,747	$	209			5.6

Plastics segment revenues increased $3.7 million as a result of an 11.2% increase in pounds of polyvinyl chloride (PVC) pipe sold. The increase in revenue was almost entirely offset by a $3.7 million increase in cost of products sold due to the increase in sales and to higher resin prices, which resulted in a 9.4% decrease in gross margin per pound of pipe sold. The Plastics segment reported increased sales in several states, but most significantly in Texas, Minnesota, Iowa and Michigan.

The PVC pipe industry is highly sensitive to commodity raw material pricing volatility. Historically, when resin prices are rising or stable, margins and sales volume have been higher and when resin prices are falling, sales volumes and margins have been lower.

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
	March 31,							%
(in thousands)	2017		2016		Change			Change
Operating Expenses	$	2,641	$	3,242	$	(601	)		(18.5	)
Depreciation and Amortization		8		12		(4	)		(33.3	)

Corporate operating expenses decreased $0.6 million, mainly as a result of a decrease in contracted services and decreased labor and benefit costs related to a reduction in the number of corporate employees combined with an increase in the level of corporate costs allocated to the Electric segment as a result of an increase in the segment’s proportional share of consolidated revenues and net income.

Interest Charges

The $0.5 million decrease in interest charges in the three months ended March 31, 2017 compared with the three months ended March 31, 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. The average level of debt outstanding between the quarters was essentially unchanged.

32 

Income Taxes – Continuing Operations

Income tax expense - continuing operations increased $0.9 million in the three months ended March 31, 2017 compared with the three months ended March 31, 2016 mainly as a result of a $5.9 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 $0.4 million increase in federal Production Tax Credits (PTCs) earned between the quarters. 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 March 31, 2017 and 2016:

	Three Months Ended March 31,
(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	25,892		$	19,982
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		10,098			7,793
Increases (Decreases) in Tax from:
Federal PTCs		(2,052	)		(1,686	)
Excess Tax Deduction – 2014 Performance Share Awards		(697	)		—
Section 199 Domestic Production Activities Deduction		(330	)		(104	)
Corporate Owned Life Insurance		(294	)		(92	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(158	)
Other Items – Net		22			(49	)
Income Tax Expense – Continuing Operations	$	6,363		$	5,492
Effective Income Tax Rate – Continuing Operations		24.6	%		27.5	%

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 24.1% in the three months ended March 31, 2017 compared with the three months ended March 31, 2016 due to improved availability of the turbines and more favorable wind and operating conditions in the first quarter 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 March 31, 2017 and December 31, 2016:

(in thousands)	Line Limit		In Use on March 31, 2017		Restricted due to Outstanding Letters of Credit		Available on March 31, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	12,825	$	—	$	117,175	$	130,000
OTP Credit Agreement		170,000		46,351		50		123,599		127,067
Total	$	300,000	$	59,176	$	50	$	240,774	$	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 quarter of 2017.

33 

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 $21.2 million for the three months ended March 31, 2017 compared with cash provided by operating activities of $22.6 million for the three months ended March 31, 2016. Contributing to the $1.4 million decrease in cash provided by continuing operations between the quarters was a $15.9 million increase in cash used for working capital items and a $0.4 million decrease in depreciation expense, offset by a $10.0 million reduction in discretionary contributions to the Company’s funded pension plan and a $5.0 million increase in net income from continuing operations. The $15.9 million increase in cash used for working capital items between the quarters includes the following major items:

· A $4.3 million increase in cash used for receivables in the Plastics segment related to an increase in PVC pipe sales in March of 2017 compared with March 2016 and an increase in outstanding receivables on March 31, 2017 from sales with extended payment terms as compared with March 31, 2016.

· A $4.2 million increase in cash used for receivables in the Electric segment in the first quarter of 2017 compared with the first quarter of 2016 as a result of increased kwh sales due to colder weather in March 2017 compared with March 2016 in combination with higher interim rates in place in March 2017.

· A $3.9 million increase in cash used for trade accounts payable in the Plastics segment, mainly related to a change in the timing of resin purchases and payments between the periods.

· A $3.6 million increase in cash used for accounts payable in the Electric segment due to a reduction in trade accounts payable in March 2017 compared with March 2016 related to the timing of payments. OTP recorded an offsetting $3.7 million increase in checks written in excess of cash between the quarters reflected in cash flows from financing activities.

In continuing operations, net cash used in investing activities was $30.0 million for the three months ended March 31, 2017 compared with $25.6 million for the three months ended March 31, 2016. The $4.4 million increase in cash used for investing activities includes a $5.3 million increase in capital expenditures, mainly at OTP as work on the Big Stone South-Brookings and Big Stone South-Ellendale 345 kV transmission line projects ramped up during 2016 and the projects are now in full construction mode. OTP also continues work on a major project to replace its customer information system. The $5.3 million increase in capital expenditures was partially offset by a $0.9 million reduction in cash used for investments and other assets as BTD’s cash invested in tooling and dies decreased by approximately $0.5 million and our captive insurance company’s cash used for investments in securities decreased by approximately $0.4 million between the quarters.

Net cash provided by financing activities of continuing operations was $8.8 million for the three months ended March 31, 2017 compared with $3.0 million for the three months ended March 31, 2016. Financing activities in the first quarter of 2017 included a net increase in short-term and long-term borrowings of $13.2 million and an increase in checks issued in excess of cash of $8.0 million, which has a direct relationship with the increase in cash used for accounts payable in the operating section of the cash flow statement, partially offset by $12.6 million in common dividend payments.

Financing activities in the first quarter of 2016 included $50 million in borrowings under a Term Loan Agreement and $3.4 million in proceeds from the issuance of stock under the automatic dividend reinvestment and share purchase plan, offset by $38.4 million in cash used to pay down short-term borrowings and checks written in excess of cash and $11.9 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.

34 

CAPITAL REQUIREMENTS

2017-2021 Capital Expenditures

The following table shows our 2016 capital expenditures and 2017 through 2021 anticipated 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 in early to mid-2018, pending regulatory reviews and other customary conditions. On the same day, OTP entered into a Turnkey Engineering, Procurement and Constructions 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 2019 for 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 March 31, 2017 OTP had capitalized approximately $3.9 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. 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 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 March 31, 2017 OTP had capitalized approximately $2.3 million in development costs associated with Astoria Station. On April 10, 2017 OTP also submitted an application for ADP to the NDPSC for its proposed development, ownership, and operation of Astoria Station.

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 quarter of 2017 as a result of an increase in 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.

35 

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. We sold no shares under this program in the first quarter of 2017.

Short-Term Debt

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

(in thousands)	Line Limit		In Use on March 31, 2017		Restricted due to Outstanding Letters of Credit		Available on March 31, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	12,825	$	—	$	117,175	$	130,000
OTP Credit Agreement		170,000		46,351		50		123,599		127,067
Total	$	300,000	$	59,176	$	50	$	240,774	$	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, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130 million. 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, 2016 the OTP Credit Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. 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 Term Loan Agreement (the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A. (JPMorgan), as administrative agent, and JPMS, as Lead Arranger and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that we may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain of our subsidiaries. Under the Term Loan Agreement, we may, on up to two occasions, enter into additional tranches of term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1) LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on our election of whether to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.

On February 5, 2016 we borrowed $50 million under the Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015 and to fund the September 1, 2015 acquisition of BTD-Georgia. We repaid $35.0 million under the Term Loan Agreement in the fourth quarter of 2016 and repaid an additional $3.0 million in the first quarter of 2017.

The Term Loan Agreement contains a number of restrictions on us, Varistar and certain subsidiaries of Varistar, including restrictions on our and their 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 Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial Covenants.” The Term Loan 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 Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.

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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.

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).

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.”

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Financial Covenants

We were in compliance with the financial covenants in our debt agreements as of March 31, 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 March 31, 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 3.91 to 1.00.

· Under the 2016 Note Purchase Agreement, we may 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 March 31, 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 3.81 to 1.00.

· 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 March 31, 2017 our ratio of Interest-bearing Debt to Total Capitalization was 0.47 to 1.00 on a consolidated basis and 0.47 to 1.00 for OTP. Neither Otter Tail Corporation or OTP had any Priority Indebtedness outstanding as of March 31, 2017.

OFF-BALANCE-SHEET ARRANGEMENTS

We and our subsidiary companies have outstanding letters of credit totaling $4.6 million, but our line of credit borrowing limits are only restricted by $50,000 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

We are reaffirming our consolidated diluted earnings per share guidance for 2017 to be in the range of $1.60 to $1.75. 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 and strategies for improving future operating results. We expect capital expenditures for 2017 to be $149 million compared with actual cash used for capital expenditures of $161 million in 2016. Major projects in our 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.

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

	2016 EPS			2017 Guidance February 6, 2017						2017 Guidance May 1, 2017
Diluted Earnings Per Share	by Segment			Low			High			Low			High
Electric	$	1.29		$	1.31		$	1.34		$	1.31		$	1.34
Manufacturing	$	0.15		$	0.17		$	0.21		$	0.17		$	0.21
Plastics	$	0.27		$	0.26		$	0.30		$	0.26		$	0.30
Corporate	$	(0.11	)	$	(0.14	)	$	(0.10	)	$	(0.14	)	$	(0.10	)
Total – Continuing Operations	$	1.60		$	1.60		$	1.75		$	1.60		$	1.75
Return on Equity		9.8	%		9.3	%		10.2	%		9.3	%		10.2	%

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 compared to normal.

o A full year of increased rates compared with 8.5 months in 2016. In March 2017, the MPUC granted OTP a revenue increase of approximately 6.3% with a 9.41% return on equity.

o Rider recovery increases, including transmission riders related to the Electric segment’s continuing investments in its share of the MVPs in South Dakota.

o Expected increases in sales to industrial and commercial customers.

offset by:

o Increased operating and maintenance expenses of $0.06 per share due to inflationary increases and increasing costs of medical, workers compensation and retiree medical benefits. 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 depreciation and property tax expense due to large capital projects being put into service.

o Lower CIP incentives of $0.04 per share in Minnesota as a result of program changes made by the MNDOC. OTP estimates the implementation of the new CIP financial incentive model will reduce these incentives by approximately 50% compared to the previous incentive mechanism.

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 Flat year-over-year sales at BTD due to lower end market recreational vehicle sales offset by higher lawn and garden end market sales, scrap, and tooling sales.

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

o Backlog for the manufacturing companies of approximately $105 million for 2017 compared with $102 million one year ago.

· We expect 2017 net income from the Plastics segment to be similar to 2016 on slightly lower sales volumes. The Plastics segment also benefits from lower interest costs as a result of the refinancing of long-term debt completed in the fourth quarter of 2016.

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

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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 March 31, 2017.

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.

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· 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.

· 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 March 31, 2017 we had exposure to market risk associated with interest rates because we had $12 million outstanding subject to a variable interest rate that is indexed to 30 day LIBOR plus 90 basis points under the Term Loan Agreement that terminates on February 5, 2018, and $12.8 million in short-term debt outstanding subject to variable interest rates indexed to LIBOR plus 1.75% under the Otter Tail Corporation Credit Agreement. OTP had $46.4 million in short-term debt outstanding on March 31, 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 March 31, 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.

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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.

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 March 31, 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 March 31, 2017.

During the fiscal quarter ended March 31, 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 2. Unregistered Sales of Equity Securities and Use of Proceeds

We do not have a publicly announced stock repurchase program. The following table shows common shares of the Company that were surrendered to us by employees to pay taxes in connection with shares issued for incentive awards in February 2017 under our 2014 Stock Incentive Plan:

Calendar Month	Total Number of Shares Purchased		Average Price Paid per Share
January 2017		—		—
February 2017		46,634	$	37.71
March 2017		—		—
Total		46,634

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Item 6. Exhibits

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 March 31, 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.

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: May 9, 2017

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EXHIBIT INDEX

Exhibit Number	Description
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 March 31, 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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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: May 9, 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: May 9, 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 March 31, 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

May 9, 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 March 31, 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

May 9, 2017

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 30, 2017
Document and Entity Information [Abstract]
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 Common Stock Shares Outstanding		39,503,539
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1

XML

Consolidated Balance Sheets (not audited) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and Cash Equivalents
Accounts Receivable:
Trade - Net	82,369	68,242
Other	7,244	5,850
Inventories	81,473	83,740
Unbilled Revenues	18,016	20,080
Income Taxes Receivable		662
Regulatory Assets	17,973	21,297
Other	11,837	8,144
Total Current Assets	218,912	208,015
Investments	8,125	8,417
Other Assets	35,416	34,104
Goodwill	37,572	37,572
Other Intangibles - Net	14,626	14,958
Regulatory Assets	128,968	132,094
Plant
Electric Plant in Service	1,868,689	1,860,357
Nonelectric Operations	212,976	211,826
Construction Work in Progress	166,866	153,261
Total Gross Plant	2,248,531	2,225,444
Less Accumulated Depreciation and Amortization	761,444	748,219
Net Plant	1,487,087	1,477,225
Total Assets	1,930,706	1,912,385
Current Liabilities
Short-Term Debt	59,176	42,883
Current Maturities of Long-Term Debt	45,192	33,201
Accounts Payable	83,622	89,350
Accrued Salaries and Wages	12,957	17,497
Accrued Federal and State Income Taxes	1,107
Other Accrued Taxes	17,068	16,000
Other Accrued Liabilities	15,584	15,377
Liabilities of Discontinued Operations	1,268	1,363
Total Current Liabilities	235,974	215,671
Pensions Benefit Liability	97,962	97,627
Other Postretirement Benefits Liability	62,796	62,571
Other Noncurrent Liabilities	22,168	21,706
Commitments and Contingencies (note 9)
Deferred Credits
Deferred Income Taxes	231,210	226,591
Deferred Tax Credits	22,483	22,849
Regulatory Liabilities	82,316	82,433
Other	6,302	7,492
Total Deferred Credits	342,311	339,365
Capitalization
Long-Term Debt - Net	490,372	505,341
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2017 - 39,468,804 Shares; 2016 - 39,348,136 Shares	197,344	196,741
Premium on Common Shares	339,036	337,684
Retained Earnings	146,438	139,479
Accumulated Other Comprehensive Loss	(3,695)	(3,800)
Total Common Equity	679,123	670,104
Total Capitalization	1,169,495	1,175,445
Total Liabilities and Equity	1,930,706	1,912,385
Cumulative Preferred Shares
Capitalization
Cumulative Shares
Cumulative Preference Shares
Capitalization
Cumulative Shares

XML

Consolidated Balance Sheets (not audited) (Parentheticals) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Common shares, par value (in dollars per share)	$ 5	$ 5
Common shares, authorized	50,000,000	50,000,000
Common shares, outstanding	39,468,804	39,348,136
Cumulative Preferred Shares
Cumulative shares, authorized	1,500,000	1,500,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding	0	0
Cumulative Preference Shares
Cumulative shares, authorized	1,000,000	1,000,000
Cumulative shares, without par value (in dollars per share)	$ 0	$ 0
Cumulative shares, outstanding	0	0

XML

Consolidated Statements of Income (not audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating Revenues
Electric	$ 118,543	$ 112,985
Product Sales	95,574	93,257
Total Operating Revenues	214,117	206,242
Operating Expenses
Production Fuel - Electric	16,382	15,700
Purchased Power - Electric	19,188	16,886
Electric Operation and Maintenance Expenses	38,379	40,018
Cost of Products Sold (depreciation included below)	75,277	72,639
Other Nonelectric Expenses	10,438	11,455
Depreciation and Amortization	17,854	18,289
Property Taxes - Electric	3,798	3,679
Total Operating Expenses	181,316	178,666
Operating Income	32,801	27,576
Interest Charges	7,462	7,994
Other Income	553	400
Income Before Income Taxes - Continuing Operations	25,892	19,982
Income Tax Expense - Continuing Operations	6,363	5,492
Net Income from Continuing Operations	19,529	14,490
Income from Discontinued Operations - net of Income Tax Expense of $38 in 2017 and $20 in 2016	56	30
Net Income	$ 19,585	$ 14,520
Average Number of Common Shares Outstanding - Basic	39,350,802	37,936,943
Average Number of Common Shares Outstanding - Diluted	39,640,725	38,045,208
Basic Earnings Per Common Share:
Continuing Operations (in dollars per share)	$ 0.50	$ 0.38
Discontinued Operations (in dollars per share)
Earnings Per Share, Basic, Total (in dollars per share)	0.50	0.38
Diluted Earnings Per Common Share:
Continuing Operations (in dollars per share)	0.49	0.38
Discontinued Operations (in dollars per share)
Earnings Per Share, Diluted, Total (in dollars per share)	0.49	0.38
Dividends Declared Per Common Share (in dollars per share)	$ 0.3200	$ 0.3125

XML

Consolidated Statements of Income (not audited) (Parentheticals) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Statement [Abstract]
Income tax expense (benefit) on income (loss) from discontinued operation	$ 38	$ 20

XML

Consolidated Statements of Comprehensive Income (not audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement Of Income and Comprehensive Income [Abstract]
Net Income	$ 19,585	$ 14,520
Unrealized Gains on Available-for-Sale Securities:
Gains Arising During Period	17	73
Income Tax Expense	(6)	(26)
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax	11	47
Pension and Postretirement Benefit Plans:
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11)	157	154
Income Tax Expense	(63)	(61)
Pension and Postretirement Benefit Plans - net-of-tax	94	93
Total Other Comprehensive Income	105	140
Total Comprehensive Income	$ 19,690	$ 14,660

XML

Consolidated Statements of Cash Flows (not audited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows from Operating Activities
Net Income	$ 19,585	$ 14,520
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Net Income from Discontinued Operations	(56)	(30)
Depreciation and Amortization	17,854	18,289
Deferred Tax Credits	(366)	(414)
Deferred Income Taxes	4,512	5,330
Change in Deferred Debits and Other Assets	5,005	2,825
Discretionary Contribution to Pension Plan		(10,000)
Change in Noncurrent Liabilities and Deferred Credits	1,314	3,363
Allowance for Equity/Other Funds Used During Construction	(170)	(95)
Stock Compensation Expense - Equity Awards	1,150	489
Other - Net	(5)	15
Cash (Used for) Provided by Current Assets and Current Liabilities:
Change in Receivables	(15,521)	(7,478)
Change in Inventories	2,267	6
Change in Other Current Assets	(22)	(773)
Change in Payables and Other Current Liabilities	(13,986)	(5,840)
Change in Interest and Income Taxes Receivable/Payable	(321)	2,400
Net Cash Provided by Continuing Operations	21,240	22,607
Net Cash (Used in) Provided by Discontinued Operations	(39)	30
Net Cash Provided by Operating Activities	21,201	22,637
Cash Flows from Investing Activities
Capital Expenditures	(30,113)	(24,855)
Net Proceeds from Disposal of Noncurrent Assets	612	682
Cash Used for Investments and Other Assets	(508)	(1,425)
Net Cash Used in Investing Activities	(30,009)	(25,598)
Cash Flows from Financing Activities
Change in Checks Written in Excess of Cash	7,999	(666)
Net Short-Term Borrowings (Repayments)	16,293	(37,736)
Proceeds from Issuance of Common Stock - net of Issuance Expenses	1,958	3,415
Payments for Retirement of Capital Stock	(1,759)	(53)
Proceeds from Issuance of Long-Term Debt		50,000
Short-Term and Long-Term Debt Issuance Expenses		(58)
Payments for Retirement of Long-Term Debt	(3,057)	(52)
Dividends Paid	(12,626)	(11,889)
Net Cash Provided by Financing Activities	8,808	2,961
Net Change in Cash and Cash Equivalents
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at End of Period

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 product. 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,590
Government-Backed and Government-Sponsored  Enterprises’ Debt Securities – Held by Captive Insurance Company				2,345
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	828
Total Assets	$	828	$	7,935

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 March 31, 2017 could be as high as $59.7 million, OTP’s 35% share of unrecovered costs.

Inventories

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

	March 31,		December 31,
(in thousands)	2017		2016
Finished Goods	$	24,018	$	27,755
Work in Process		12,801		11,754
Raw Material, Fuel and Supplies		44,654		44,231
Total Inventories	$	81,473	$	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 three 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) March 31, 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,144	$	14,347	33-221 months
Covenant not to Compete		590		311		279	17 months
Total	$	23,081	$	8,455	$	14,626
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36-224 months
Covenant not to Compete		590		262		328	20 months
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Amortization Expense – Intangible Assets	$	332	$	357

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	$	1,330	$	1,264	$	1,133	$	1,099	$	1,099

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2017		2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,811	$	24,618

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 is 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. As of March 31, 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 evaluating transition options. 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 treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice. 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. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

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, developing a list of all current leases outstanding and identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and 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 what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated income statements upon adoption of the amendments in ASU 2017-07. 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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Segment Information

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Segment Information

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 material and handling trays and horticultural containers. 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 98.4% and 97.6% of its operating revenues for the respective three month periods ended March 31, 2017 and 2016 came from sales within the United States.

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 months ended March 31, 2017 and 2016 and total assets by business segment as of March 31, 2017 and December 31, 2016 are presented in the following tables:

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	118,551		$	112,994
Manufacturing		58,417			59,820
Plastics		37,157			33,437
Intersegment Eliminations		(8	)		(9	)
Total	$	214,117		$	206,242

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Electric	$	6,386	$	6,284
Manufacturing		554		992
Plastics		153		244
Corporate and Intersegment Eliminations		369		474
Total	$	7,462	$	7,994

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	6,062		$	4,612
Manufacturing		1,055			1,019
Plastics		1,390			1,367
Corporate		(2,144	)		(1,506	)
Total	$	6,363		$	5,492

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	15,560		$	12,538
Manufacturing		2,172			1,853
Plastics		2,437			2,152
Corporate		(640	)		(2,053	)
Discontinued Operations		56			30
Total	$	19,585		$	14,520

Identifiable Assets

	March 31,		December 31,
(in thousands)	2017		2016
Electric	$	1,630,071	$	1,622,231
Manufacturing		170,805		166,525
Plastics		91,049		84,592
Corporate		38,781		39,037
Total	$	1,930,706	$	1,912,385

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Rate and Regulatory Matters

3 Months Ended

Mar. 31, 2017

Rate and Regulatory Matters [Abstract]

Rate and Regulatory Matters

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

The Big Stone South – Brookings Multi-Value Transmission Project (MVP) and Capacity Expansion 2020 (CapX2020) Project—This 345 kiloVolt (kV) transmission line, currently under construction, will extend 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 (NSP MN), a subsidiary of Xcel Energy Inc., jointly developed this project 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 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 is expected to be in service in fall 2017. OTP’s capitalized costs on this project as of March 31, 2017 were approximately $64.0 million, which includes assets that are 100% owned by OTP.

The 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. (MDU), 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 March 31, 2017 were approximately $57.9 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—On February 16, 2016 OTP filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5% of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information is detailed in the table below:

($ in thousands)	Annualized or Test Year			Actual Through March 31, 2017
Revenue Increase Requested	$	19,296
Increase Percentage Requested		9.80	%
Jurisdictional Rate Base	$	483,000
Interim Revenue Increase (subject to refund)	$	16,816		$	15,335

The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity.

Oral arguments before the MPUC occurred February 23, 2017 with deliberations on March 2, 2017. The MPUC rendered its final decision in March 2017 and issued its written order on May 1, 2017. The MPUC authorized a revenue increase of approximately $12.3 million through a 6.27% increase in base rate revenues compared to the authorized interim rate increase of 9.56%. The MPUC’s written order included: (1) an allowed rate of return on equity of 9.41%, (2) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South to Brookings and Big Stone South to Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (3) 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 at the time final rates are implemented at the end of this rate case. 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. 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%. OTP's rate of return will be based on a capital structure of 47.50% long term debt and 52.50% common equity. Parties may request clarification or reconsideration of the MPUC’s rulings consistent with Minnesota law. Based on the MPUC deliberations regarding OTP’s 2016 revenue increase request, OTP had recorded an estimated interim rate refund of $5.2 million, including interest, as of March 31, 2017.

2010 General Rate Case—A general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed rate of return on equity increased from 10.43% to 10.74%.

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 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 requested for 2016, $4.3 million approved for 2015 and $3.0 million approved for 2014. The MNDOC recently granted two large customers’ requests for exemption from OTP’s MNCIP pursuant to Minnesota Law. With the exemption of these two customers, recovery of the portion of OTP’s MNCIP costs previously recovered from these two customers has shifted to OTP’s other Minnesota customers.

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, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s share of 100% 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, despite an ALJ recommendation that the MPUC affirm OTP’s proposed treatment. The MPUC ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes.

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.

North Dakota

General Rates—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 the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. 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. 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 Mercury and Air Toxics Standards (MATS) projects.

Rate Rider Updates

The following table provides summary information on the status of updates for the previous two years for the various 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	R – March 31, 2017	October 1, 2017	$	9,868	$0.00754/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
2016 Annual Update1	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
2016 Annual Update1	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
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	R – March 31, 2017	July 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
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 and subject to change based on comments from the MNDOC.

Revenues Recorded under Rate Riders

The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31:

Rate Rider (in thousands)	2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,966	$	2,506
Transmission Cost Recovery		2,170		2,276
Environmental Cost Recovery		2,824		3,082
North Dakota
Renewable Resource Adjustment		1,770		2,059
Transmission Cost Recovery		2,511		2,236
Environmental Cost Recovery		2,488		2,811
South Dakota
Transmission Cost Recovery		441		651
Environmental Cost Recovery		597		633
Conservation Improvement Program Costs and Incentives		240		159

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 of 1935, as amended. 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 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%.

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%. A lack of a quorum at FERC will delay the issuance of an order in the second complaint for an uncertain period of time.

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 90% of the FERC ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period in its February 2017 billings. 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 on December 31, 2016 to $1.7 million as of March 31, 2017.

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2017

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

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:

	March 31, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,443	$	106,656	$	113,099	see below
Deferred Marked-to-Market Losses1		4,063		5,452		9,515	45 months
Conservation Improvement Program Costs and Incentives2		3,745		5,735		9,480	30 months
Accumulated ARO Accretion/Depreciation Adjustment1		—		6,276		6,276	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		739		1,926		2,665	49 months
Debt Reacquisition Premiums1		301		1,150		1,451	186 months
Deferred Income Taxes1		—		1,020		1,020	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery1		954		—		954	12 months
North Dakota Renewable Resource Rider Accrued Revenues2		727		62		789	24 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		517		617	74 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		426		59		485	21 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		251		115		366	21 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		106		—		106	11 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		95		—		95	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		23		—		23	6 months
Total Regulatory Assets	$	17,973	$	128,968	$	146,941
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	81,314	$	81,314	asset lives
Refundable Fuel Clause Adjustment Revenues		2,119		—		2,119	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,545		—		1,545	12 months
Deferred Income Taxes		—		785		785	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		30		741	13 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		631		—		631	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		354		—		354	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		299		—		299	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		33		99		132	21 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		8		—		8	12 months
Other		6		88		94	201 months
Total Regulatory Liabilities	$	5,706	$	82,316	$	88,022
Net Regulatory Asset Position	$	12,267	$	46,652	$	58,919

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.

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

All Deferred Marked-to-Market Losses recorded as of March 31, 2017 relate to forward purchases of energy scheduled for delivery through December 2020.

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

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

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 186 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.

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.

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 March 31, 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.

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 March 31, 2017.

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.

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 March 31, 2017.

The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 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 North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 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 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 March 31, 2017.

The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 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 March 31, 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 March 31, 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.

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Open Contract Positions Subject to Legally Enforceable Netting Arrangements

3 Months Ended

Mar. 31, 2017

Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]

Open Contract Positions Subject to Legally Enforceable Netting Arrangements

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 March 31, 2017 and December 31, 2016:

(in thousands)	March 31, 2017			December 31, 2016
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	—		$	—
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(14,590	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(14,590	)	$	(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 March 31, 2017 and December 31, 2016:

(in thousands)	March 31, 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		14,590		17,382
Total Loss Contracts based on Current Market Values	$	14,590	$	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	$	14,590	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		—		—
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	14,590	$	17,382

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

3 Months Ended

Mar. 31, 2017

Stockholders Equity and Earnings Per Share [Abstract]

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

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		837			1,727									2,564
Common Stock Retirements		(234	)		(1,525	)								(1,759	)
Net Income								19,585						19,585
Other Comprehensive Income											105			105
Employee Stock Incentive Plans Expense					1,150									1,150
Common Dividends ($0.32 per share)								(12,626	)					(12,626	)
Balance, March 31, 2017	$	197,344		$	339,036		$	146,438		$	(3,695	)	$	679,123

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 March 31, 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	36,320
Cash Invested	11,750
Employee Stock Ownership Plan	14,835
Vesting of Restricted Stock Units	9,975
Employee Stock Purchase Plan:
Cash Invested	—
Dividends Reinvested	5,131
Retirements:
Shares Withheld for Individual Income Tax Requirements	(46,634	)
Common Shares Outstanding, March 31, 2017	39,468,804

Earnings Per Share

The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 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 for the three month periods ended March 31:

	2017		2016
Weighted Average Common Shares Outstanding – Basic		39,350,802		37,936,943
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		201,639		46,885
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		57,873		39,841
Nonvested Restricted Shares		27,069		17,776
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,342		3,763
Total Dilutive Shares		289,923		108,265
Weighted Average Common Shares Outstanding – Diluted		39,640,725		38,045,208

The effect of dilutive shares on earnings per share for the three month periods ended March 31, 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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Share-Based Payments

3 Months Ended

Mar. 31, 2017

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Share-Based Payments

7. Share-Based Payments

Stock Incentive Awards

On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan:

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,900	$	37.65	25% per year through February 6, 2021
Stock Performance Awards Granted		59,500	$	31.00	December 31, 2019

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 was the average of the high and low market price per share on the date of grant.

Under the performance share awards, the aggregate award for performance at target is 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 return on equity. 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 terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award.

Under the 2017 Performance Award Agreements, payment and 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 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 March 31, 2017 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.3 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years.

Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2017 and 2016 are presented in the table below:

	Three months ended
	March 31,
(in thousands)	2017		2016
Stock Performance Awards Granted to Executive Officers	$	649	$	537
Restricted Stock Units Granted to Executive Officers		264		245
Restricted Stock Granted to Executive Officers		22		29
Restricted Stock Granted to Directors		128		107
Restricted Stock Units Granted to Non-Executive Employees		87		64
Employee Stock Purchase Plan (15% discount)		—		44
Totals	$	1,150	$	1,026

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Retained Earnings Restriction

3 Months Ended

Mar. 31, 2017

Retained Earnings Restrictions [Abstract]

Retained Earnings Restriction

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 March 31, 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 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. As of March 31, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $443,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

9. Commitments and Contingencies

Construction and Other Purchase Commitments

At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $84.8 million. At March 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $114.6 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 OTP rolled forward a portion of its coal supply for Big Stone Plant that it expected to take delivery of in 2016 into 2018 and entered into an agreement to purchase additional tons in 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 for the period of January 1, 2016 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 2017 MISO billings MISO processed the refund of 90% 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 $1.7 million as of March 31, 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 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. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. The parties have been unable to settle the issues on appeal and the cases will likely revert to the active calendar of the D.C. Circuit. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, 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. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse 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 proposed standards of performance for carbon dioxide (CO₂) emissions from new, reconstructed and modified fossil fuel-fired power plants 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. All of these rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. 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 and, if a petition for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. 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 has now issued orders holding in abeyance both the appeals on new, reconstructed and modified fossil fuel-fired power plants and the Clean Power Plan, pending EPA review. Therefore, while the Clean Power Plan remains stayed, there is uncertainty regarding its future, and each of the CO₂ rules could change, at least to some extent, through future agency action.

Other

The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2017 will not be material.

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Short-Term and Long-Term Borrowings

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Short-Term and Long-Term Borrowings

10. Short-Term and Long-Term Borrowings

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

(in thousands)	Line Limit		In Use on March 31, 2017		Restricted due to Outstanding Letters of Credit		Available on March 31, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	12,825	$	—	$	117,175	$	130,000
OTP Credit Agreement		170,000		46,351		50		123,599		127,067
Total	$	300,000	$	59,176	$	50	$	240,774	$	257,067

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 repaid an additional $3.0 million in the first quarter of 2017.

The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	46,351	$	12,825	$	59,176
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	12,000	$	12,000
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				86		86
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				799		799
Total	$	445,000	$	92,885	$	537,885
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,981		12,211		45,192
Unamortized Long-Term Debt Issuance Costs		1,801		520		2,321
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,218	$	80,154	$	490,372
Total Short-Term and Long-Term Debt (with current maturities)	$	489,550	$	105,190	$	594,740

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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Pension Plan and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2017

Compensation and Retirement Disclosure [Abstract]

Pension Plan and Other Postretirement Benefits

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 March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	1,407		$	1,382
Interest Cost on Projected Benefit Obligation		3,534			3,522
Expected Return on Assets		(4,807	)		(4,867	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			47
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,227
From Other Comprehensive Income1		31			31
Net Periodic Pension Cost	$	1,469		$	1,343
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 March 31,
(in thousands)	2017		2016
Service Cost—Benefit Earned During the Period	$	73	$	63
Interest Cost on Projected Benefit Obligation		422		417
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income1		9		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		71		73
From Other Comprehensive Income2		110		112
Net Periodic Pension Cost	$	689	$	678
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	4
Other Nonelectric Expenses		5		5
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	66	$	68
Other Nonelectric Expenses		44		44

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 March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	356		$	306
Interest Cost on Projected Benefit Obligation		678			541
Amortization of Prior-Service Costs:
From Regulatory Asset		—			33
From Other Comprehensive Income1		—			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			—
From Other Comprehensive Income1		6			—
Net Periodic Postretirement Benefit Cost	$	1,273		$	881
Effect of Medicare Part D Subsidy	$	(140	)	$	(257	)
1 Corporate cost included in Other Nonelectric Expenses.

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

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:

Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 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.

	March 31, 2017						December 31, 2016
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Short-Term Debt		(59,176	)		(59,176	)		(42,883	)		(42,883	)
Long-Term Debt including Current Maturities		(535,564	)		(582,743	)		(538,542	)		(583,835	)

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Income Tax Expense - Continuing Operations

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Tax Expense - Continuing Operations

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 for the three month periods ended March 31, 2017 and 2016:

	Three Months Ended March 31,
(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	25,892		$	19,982
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		10,098			7,793
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,052	)		(1,686	)
Excess Tax Deduction – 2014 Performance Share Awards		(697	)		—
Section 199 Domestic Production Activities Deduction		(330	)		(104	)
Corporate Owned Life Insurance		(294	)		(92	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(158	)
Other Items – Net		22			(49	)
Income Tax Expense – Continuing Operations	$	6,363		$	5,492
Effective Income Tax Rate – Continuing Operations		24.6	%		27.5	%

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		—		—
Increases Related to Tax Positions for Current Year		43		16
Uncertain Positions Resolved During Year		—		—
Balance on March 31	$	934	$	484

The balance of unrecognized tax benefits as of March 31, 2017 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 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 March 31, 2017.

The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of March 31, 2017, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes.

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Discontinued Operations

3 Months Ended

Mar. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

16. Discontinued Operations

Included in discontinued operations are activities related to the Company’s former wind tower manufacturing business and dock and boatlift company. 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		(1	)		—
Decrease in Warranty Estimates for Prior Years		(100	)		—
Warranty Reserve Balance, March 31	$	1,268		$	2,103

The warranty reserve balances as of March 31, 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 one to 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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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Revenue Recognition

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 product. The shipping terms used in these instances are FOB shipping point.

Agreements Subject to Legally Enforceable Netting Arrangements

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

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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,590
Government-Backed and Government-Sponsored  Enterprises’ Debt Securities – Held by Captive Insurance Company				2,345
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	828
Total Assets	$	828	$	7,935

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

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 March 31, 2017 could be as high as $59.7 million, OTP’s 35% share of unrecovered costs.

Inventories

Inventories

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

	March 31,		December 31,
(in thousands)	2017		2016
Finished Goods	$	24,018	$	27,755
Work in Process		12,801		11,754
Raw Material, Fuel and Supplies		44,654		44,231
Total Inventories	$	81,473	$	83,740

Goodwill and Other Intangible Assets

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 three 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) March 31, 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 March 31, 2017 and December 31, 2016:

March 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,144	$	14,347	33-221 months
Covenant not to Compete		590		311		279	17 months
Total	$	23,081	$	8,455	$	14,626
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36-224 months
Covenant not to Compete		590		262		328	20 months
Total	$	23,081	$	8,123	$	14,958

The amortization expense for these intangible assets was:

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Amortization Expense – Intangible Assets	$	332	$	357

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	$	1,330	$	1,264	$	1,133	$	1,099	$	1,099

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

	As of March 31,
(in thousands)	2017		2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,811	$	24,618

New Accounting Standards Adopted

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 is 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

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. As of March 31, 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 evaluating transition options. 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 treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice. 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. The Company does not plan to adopt the updated guidance prior to January 1, 2018.

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, developing a list of all current leases outstanding and identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and 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 what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated income statements upon adoption of the amendments in ASU 2017-07. 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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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Accounting Policies [Abstract]

Schedule of assets and liabilities that are measured at fair value on a recurring basis

March 31, 2017 (in thousands)	Level 1		Level 2		Level 3
Assets:
Investments:
Corporate Debt Securities – Held by Captive Insurance Company			$	5,590
Government-Backed and Government-Sponsored  Enterprises’ Debt Securities – Held by Captive Insurance Company				2,345
Other Assets:
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan	$	828
Total Assets	$	828	$	7,935

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

Schedule of inventories

	March 31,		December 31,
(in thousands)	2017		2016
Finished Goods	$	24,018	$	27,755
Work in Process		12,801		11,754
Raw Material, Fuel and Supplies		44,654		44,231
Total Inventories	$	81,473	$	83,740

Schedule of changes to goodwill by business segment

(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) March 31, 2017
Manufacturing	$	18,270	$	—	$	18,270	$	—	$	18,270
Plastics		19,302		—		19,302		—		19,302
Total	$	37,572	$	—	$	37,572	$	—	$	37,572

Schedule of components of intangible assets

March 31, 2017 (in thousands)	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Remaining Amortization Periods
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	8,144	$	14,347	33-221 months
Covenant not to Compete		590		311		279	17 months
Total	$	23,081	$	8,455	$	14,626
December 31, 2016 (in thousands)
Amortizable Intangible Assets:
Customer Relationships	$	22,491	$	7,861	$	14,630	36-224 months
Covenant not to Compete		590		262		328	20 months
Total	$	23,081	$	8,123	$	14,958

Schedule of amortization expense for intangible assets

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Amortization Expense – Intangible Assets	$	332	$	357

Schedule of estimated annual amortization expense for intangible assets

(in thousands)	2017		2018		2019		2020		2021
Estimated Amortization Expense – Intangible Assets	$	1,330	$	1,264	$	1,133	$	1,099	$	1,099

Schedule of supplemental disclosure of cash flow information

	As of March 31,
(in thousands)	2017		2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$	10,811	$	24,618

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Schedule of information by business segments

Operating Revenue

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	118,551		$	112,994
Manufacturing		58,417			59,820
Plastics		37,157			33,437
Intersegment Eliminations		(8	)		(9	)
Total	$	214,117		$	206,242

Interest Charges

	Three Months Ended
	March 31,
(in thousands)	2017		2016
Electric	$	6,386	$	6,284
Manufacturing		554		992
Plastics		153		244
Corporate and Intersegment Eliminations		369		474
Total	$	7,462	$	7,994

Income Taxes

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	6,062		$	4,612
Manufacturing		1,055			1,019
Plastics		1,390			1,367
Corporate		(2,144	)		(1,506	)
Total	$	6,363		$	5,492

Net Income (Loss)

	Three Months Ended
	March 31,
(in thousands)	2017			2016
Electric	$	15,560		$	12,538
Manufacturing		2,172			1,853
Plastics		2,437			2,152
Corporate		(640	)		(2,053	)
Discontinued Operations		56			30
Total	$	19,585		$	14,520

Identifiable Assets

	March 31,		December 31,
(in thousands)	2017		2016
Electric	$	1,630,071	$	1,622,231
Manufacturing		170,805		166,525
Plastics		91,049		84,592
Corporate		38,781		39,037
Total	$	1,930,706	$	1,912,385

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Rate and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2017

Rate and Regulatory Matters [Abstract]

Schedule of request and interim rate information

($ in thousands)	Annualized or Test Year			Actual Through March 31, 2017
Revenue Increase Requested	$	19,296
Increase Percentage Requested		9.80	%
Jurisdictional Rate Base	$	483,000
Interim Revenue Increase (subject to refund)	$	16,816		$	15,335

Schedule of information on status of updates for previous periods

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	R – March 31, 2017	October 1, 2017	$	9,868	$0.00754/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
2016 Annual Update1	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
2016 Annual Update1	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
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	R – March 31, 2017	July 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
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 and subject to change based on comments from the MNDOC.

Schedule of revenues recorded under rate riders

Rate Rider (in thousands)	2017		2016
Minnesota
Conservation Improvement Program Costs and Incentives1	$	1,966	$	2,506
Transmission Cost Recovery		2,170		2,276
Environmental Cost Recovery		2,824		3,082
North Dakota
Renewable Resource Adjustment		1,770		2,059
Transmission Cost Recovery		2,511		2,236
Environmental Cost Recovery		2,488		2,811
South Dakota
Transmission Cost Recovery		441		651
Environmental Cost Recovery		597		633
Conservation Improvement Program Costs and Incentives		240		159

¹Includes MNCIP costs recovered in base rates.

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2017

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of amount of regulatory assets and liabilities

	March 31, 2017						Remaining Recovery/
(in thousands)	Current		Long-Term		Total		Refund Period
Regulatory Assets:
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1	$	6,443	$	106,656	$	113,099	see below
Deferred Marked-to-Market Losses1		4,063		5,452		9,515	45 months
Conservation Improvement Program Costs and Incentives2		3,745		5,735		9,480	30 months
Accumulated ARO Accretion/Depreciation Adjustment1		—		6,276		6,276	asset lives
Big Stone II Unrecovered Project Costs – Minnesota1		739		1,926		2,665	49 months
Debt Reacquisition Premiums1		301		1,150		1,451	186 months
Deferred Income Taxes1		—		1,020		1,020	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery1		954		—		954	12 months
North Dakota Renewable Resource Rider Accrued Revenues2		727		62		789	24 months
Big Stone II Unrecovered Project Costs – South Dakota2		100		517		617	74 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues2		426		59		485	21 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up2		251		115		366	21 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues2		106		—		106	11 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues2		95		—		95	12 months
Minnesota Renewable Resource Rider Accrued Revenues2		23		—		23	6 months
Total Regulatory Assets	$	17,973	$	128,968	$	146,941
Regulatory Liabilities:
Accumulated Reserve for Estimated Removal Costs – Net of Salvage	$	—	$	81,314	$	81,314	asset lives
Refundable Fuel Clause Adjustment Revenues		2,119		—		2,119	12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund		1,545		—		1,545	12 months
Deferred Income Taxes		—		785		785	asset lives
Revenue for Rate Case Expenses Subject to Refund – Minnesota		711		30		741	13 months
Minnesota Environmental Cost Recovery Rider Accrued Refund		631		—		631	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund		354		—		354	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund		299		—		299	12 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up		33		99		132	21 months
South Dakota Transmission Cost Recovery Rider Accrued Refund		8		—		8	12 months
Other		6		88		94	201 months
Total Regulatory Liabilities	$	5,706	$	82,316	$	88,022
Net Regulatory Asset Position	$	12,267	$	46,652	$	58,919

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.

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

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Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables)

3 Months Ended

Mar. 31, 2017

Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract]

Schedule of derivative asset and liability balances subject to legally enforceable netting arrangements

(in thousands)	March 31, 2017			December 31, 2016
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements	$	—		$	—
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements		(14,590	)		(17,382	)
Net Balance Subject to Legally Enforceable Netting Arrangements	$	(14,590	)	$	(17,382	)

Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions

(in thousands)	March 31, 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		14,590		17,382
Total Loss Contracts based on Current Market Values	$	14,590	$	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	$	14,590	$	17,382
Offsetting Gains with Counterparties under Master Netting Agreements		—		—
Reporting Date Deposit Requirement if Credit Risk Feature Triggered	$	14,590	$	17,382

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

Stockholders Equity and Earnings Per Share [Abstract]

Schedule of 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		837			1,727									2,564
Common Stock Retirements		(234	)		(1,525	)								(1,759	)
Net Income								19,585						19,585
Other Comprehensive Income											105			105
Employee Stock Incentive Plans Expense					1,150									1,150
Common Dividends ($0.32 per share)								(12,626	)					(12,626	)
Balance, March 31, 2017	$	197,344		$	339,036		$	146,438		$	(3,695	)	$	679,123

Schedule of common shares outstanding from December 31, 2015 through March 31, 2016

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	36,320
Cash Invested	11,750
Employee Stock Ownership Plan	14,835
Vesting of Restricted Stock Units	9,975
Employee Stock Purchase Plan:
Cash Invested	—
Dividends Reinvested	5,131
Retirements:
Shares Withheld for Individual Income Tax Requirements	(46,634	)
Common Shares Outstanding, March 31, 2017	39,468,804

Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted

	2017		2016
Weighted Average Common Shares Outstanding – Basic		39,350,802		37,936,943
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		201,639		46,885
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees		57,873		39,841
Nonvested Restricted Shares		27,069		17,776
Shares Expected to be Issued Under the Deferred Compensation Program for Directors		3,342		3,763
Total Dilutive Shares		289,923		108,265
Weighted Average Common Shares Outstanding – Diluted		39,640,725		38,045,208

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Share-Based Payments (Tables)

3 Months Ended

Mar. 31, 2017

Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract]

Schedule of stock incentive awards granted

Award	Shares/Units Granted		Weighted Average Grant-Date Fair Value per Award		Vesting
Restricted Stock Units Granted		15,900	$	37.65	25% per year through February 6, 2021
Stock Performance Awards Granted		59,500	$	31.00	December 31, 2019

Schedule of compensation expense under stock-based payment programs

	Three months ended
	March 31,
(in thousands)	2017		2016
Stock Performance Awards Granted to Executive Officers	$	649	$	537
Restricted Stock Units Granted to Executive Officers		264		245
Restricted Stock Granted to Executive Officers		22		29
Restricted Stock Granted to Directors		128		107
Restricted Stock Units Granted to Non-Executive Employees		87		64
Employee Stock Purchase Plan (15% discount)		—		44
Totals	$	1,150	$	1,026

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Short-Term and Long-Term Borrowings (Tables)

3 Months Ended

Mar. 31, 2017

Debt Disclosure [Abstract]

Schedule of lines of credit

(in thousands)	Line Limit		In Use on March 31, 2017		Restricted due to Outstanding Letters of Credit		Available on March 31, 2017		Available on December 31, 2016
Otter Tail Corporation Credit Agreement	$	130,000	$	12,825	$	—	$	117,175	$	130,000
OTP Credit Agreement		170,000		46,351		50		123,599		127,067
Total	$	300,000	$	59,176	$	50	$	240,774	$	257,067

Schedule of short-term and long-term debt outstanding

March 31, 2017 (in thousands)	OTP		Otter Tail Corporation		Otter Tail Corporation Consolidated
Short-Term Debt	$	46,351	$	12,825	$	59,176
Long-Term Debt:
Term Loan, LIBOR plus 0.90%, due February 5, 2018			$	12,000	$	12,000
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				86		86
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021				799		799
Total	$	445,000	$	92,885	$	537,885
Less: Current Maturities net of Unamortized Debt Issuance Costs		32,981		12,211		45,192
Unamortized Long-Term Debt Issuance Costs		1,801		520		2,321
Total Long-Term Debt net of Unamortized Debt Issuance Costs	$	410,218	$	80,154	$	490,372
Total Short-Term and Long-Term Debt (with current maturities)	$	489,550	$	105,190	$	594,740

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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Pension Plan and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2017

Pension Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	1,407		$	1,382
Interest Cost on Projected Benefit Obligation		3,534			3,522
Expected Return on Assets		(4,807	)		(4,867	)
Amortization of Prior-Service Cost:
From Regulatory Asset		30			47
From Other Comprehensive Income1		1			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273			1,227
From Other Comprehensive Income1		31			31
Net Periodic Pension Cost	$	1,469		$	1,343
1Corporate cost included in Other Nonelectric Expenses.

Executive Survivor and Supplemental Retirement Plan

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2017		2016
Service Cost—Benefit Earned During the Period	$	73	$	63
Interest Cost on Projected Benefit Obligation		422		417
Amortization of Prior-Service Cost:
From Regulatory Asset		4		4
From Other Comprehensive Income1		9		9
Amortization of Net Actuarial Loss:
From Regulatory Asset		71		73
From Other Comprehensive Income2		110		112
Net Periodic Pension Cost	$	689	$	678
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	4	$	4
Other Nonelectric Expenses		5		5
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
Electric Operation and Maintenance Expenses	$	66	$	68
Other Nonelectric Expenses		44		44

Postretirement Benefits

Schedule of components of net periodic postretirement benefit cost

	Three Months Ended March 31,
(in thousands)	2017			2016
Service Cost—Benefit Earned During the Period	$	356		$	306
Interest Cost on Projected Benefit Obligation		678			541
Amortization of Prior-Service Costs:
From Regulatory Asset		—			33
From Other Comprehensive Income1		—			1
Amortization of Net Actuarial Loss:
From Regulatory Asset		233			—
From Other Comprehensive Income1		6			—
Net Periodic Postretirement Benefit Cost	$	1,273		$	881
Effect of Medicare Part D Subsidy	$	(140	)	$	(257	)
1 Corporate cost included in Other Nonelectric Expenses.

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Schedule of long-term debt including current maturities

	March 31, 2017						December 31, 2016
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Short-Term Debt		(59,176	)		(59,176	)		(42,883	)		(42,883	)
Long-Term Debt including Current Maturities		(535,564	)		(582,743	)		(538,542	)		(583,835	)

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Income Tax Expense - Continuing Operations (Tables)

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of income from continuing operations before income taxes and income tax expense

	Three Months Ended March 31,
(in thousands)	2017			2016
Income Before Income Taxes – Continuing Operations	$	25,892		$	19,982
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)		10,098			7,793
Increases (Decreases) in Tax from:
Federal Production Tax Credits		(2,052	)		(1,686	)
Excess Tax Deduction – 2014 Performance Share Awards		(697	)		—
Section 199 Domestic Production Activities Deduction		(330	)		(104	)
Corporate Owned Life Insurance		(294	)		(92	)
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes		(212	)		(212	)
Employee Stock Ownership Plan Dividend Deduction		(172	)		(158	)
Other Items – Net		22			(49	)
Income Tax Expense – Continuing Operations	$	6,363		$	5,492
Effective Income Tax Rate – Continuing Operations		24.6	%		27.5	%

Schedule of activity related to unrecognized tax benefits

(in thousands)	2017		2016
Balance on January 1	$	891	$	468
Increases Related to Tax Positions for Prior Years		—		—
Increases Related to Tax Positions for Current Year		43		16
Uncertain Positions Resolved During Year		—		—
Balance on March 31	$	934	$	484

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Schedule of warranty reserves

(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		(1	)		—
Decrease in Warranty Estimates for Prior Years		(100	)		—
Warranty Reserve Balance, March 31	$	1,268		$	2,103

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Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Level 1
Assets:
Total Assets	$ 828	$ 849
Level 1 | Money Market and Mutual Funds
Assets:
Other Assets - Nonqualified Retirement Savings Plan	828	849
Level 2
Assets:
Total Assets	7,935	8,225
Level 2 | Corporate Debt Securities
Assets:
Investments - Held by Captive Insurance Company	5,590	5,280
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities
Assets:
Investments - Held by Captive Insurance Company	$ 2,345	$ 2,945

XML

Summary of Significant Accounting Policies - Inventories (Details 1) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Finished Goods	$ 24,018	$ 27,755
Work in Process	12,801	11,754
Raw Material, Fuel and Supplies	44,654	44,231
Total Inventories	$ 81,473	$ 83,740

XML

Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 2) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Goodwill [Roll Forward]
Gross Balance December 31, 2016	$ 37,572
Accumulated Impairments
Balance (net of impairments) December 31, 2016	37,572
Adjustments to Goodwill in 2017
Balance (net of impairments) March 31, 2017	37,572
Manufacturing
Goodwill [Roll Forward]
Gross Balance December 31, 2016	18,270
Accumulated Impairments
Balance (net of impairments) December 31, 2016	18,270
Adjustments to Goodwill in 2017
Balance (net of impairments) March 31, 2017	18,270
Plastics
Goodwill [Roll Forward]
Gross Balance December 31, 2016	19,302
Accumulated Impairments
Balance (net of impairments) December 31, 2016	19,302
Adjustments to Goodwill in 2017
Balance (net of impairments) March 31, 2017	$ 19,302

XML

Summary of Significant Accounting Policies - Components of intangible assets (Details 3) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Amortizable Intangible Assets:
Gross Carrying Amount	$ 23,081	$ 23,081
Accumulated Amortization	8,455	8,123
Net Carrying Amount	14,626	14,958
Customer Relationships
Amortizable Intangible Assets:
Gross Carrying Amount	22,491	22,491
Accumulated Amortization	8,144	7,861
Net Carrying Amount	$ 14,347	$ 14,630
Customer Relationships | Minimum
Amortizable Intangible Assets:
Remaining Amortization Periods	33 months	36 months
Customer Relationships | Maximum
Amortizable Intangible Assets:
Remaining Amortization Periods	221 months	224 months
Covenant not to Compete
Amortizable Intangible Assets:
Gross Carrying Amount	$ 590	$ 590
Accumulated Amortization	311	262
Net Carrying Amount	$ 279	$ 328
Remaining Amortization Periods	17 months	20 months

XML

Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 4) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accounting Policies [Abstract]
Amortization Expense - Intangible Assets	$ 332	$ 357

XML

Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 5) $ in Thousands	Mar. 31, 2017 USD ($)
Estimated Amortization Expense - Intangible Assets
2017	$ 1,330
2018	1,264
2019	1,133
2020	1,099
2021	$ 1,099

XML

Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 6) - USD ($) $ in Thousands	Mar. 31, 2017	Mar. 31, 2016
Noncash Investing Activities:
Transactions Related to Capital Additions not Settled in Cash	$ 10,811	$ 24,618

XML

Summary of Significant Accounting Policies (Detail Textuals) - Coyote Creek Mining Company, L.L.C. (CCMC) - Lignite Sales Agreement - Otter Tail Power Company $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Significant Accounting Policies [Line Items]
Maximum exposure to loss as a result of involvement with CCMC	$ 59.7
Percentage of development period costs, development fees and capital charge incurred by CCMC	35.00%

XML

Segment Information - Information on continuing operations for business segments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Operating Revenue	$ 214,117	$ 206,242
Interest Charges	7,462	7,994
Income Taxes	6,363	5,492
Net Income (Loss)	19,585	14,520
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenue	(8)	(9)
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Interest Charges	369	474
Corporate
Segment Reporting Information [Line Items]
Income Taxes	(2,144)	(1,506)
Net Income (Loss)	(640)	(2,053)
Discontinued Operations
Segment Reporting Information [Line Items]
Net Income (Loss)	56	30
Electric | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	118,551	112,994
Interest Charges	6,386	6,284
Income Taxes	6,062	4,612
Net Income (Loss)	15,560	12,538
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	58,417	59,820
Interest Charges	554	992
Income Taxes	1,055	1,019
Net Income (Loss)	2,172	1,853
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenue	37,157	33,437
Interest Charges	153	244
Income Taxes	1,390	1,367
Net Income (Loss)	$ 2,437	$ 2,152

XML

Segment Information - Total assets by business segment (Details 1) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 1,930,706	$ 1,912,385
Corporate
Segment Reporting Information [Line Items]
Assets	38,781	39,037
Electric | Operating Segments
Segment Reporting Information [Line Items]
Assets	1,630,071	1,622,231
Manufacturing | Operating Segments
Segment Reporting Information [Line Items]
Assets	170,805	166,525
Plastics | Operating Segments
Segment Reporting Information [Line Items]
Assets	$ 91,049	$ 84,592

XML

Segment Information (Detail Textuals) - Operating revenues	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Concentration Risk [Line Items]
Operating revenues, benchmark description			No single customer accounted for over 10% of the Company's consolidated revenues
UNITED STATES
Concentration Risk [Line Items]
Operating revenues, percentage	98.40%	97.60%

XML

Segment Information (Detail Textuals 1)	3 Months Ended
	Mar. 31, 2017 Segment
Segment Reporting [Abstract]
Number of reportable segments	3

XML

Rate and Regulatory Matters - Summary of interim rate information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)
Public Utilities, General Disclosures [Line Items]
Interim Revenue Increase (subject to refund)	$ 15,335
2017 Test Year Allocation
Public Utilities, General Disclosures [Line Items]
Revenue Increase Requested	$ 19,296
Increase Percentage Requested	9.80%
Jurisdictional Rate Base	$ 483,000
Interim Revenue Increase (subject to refund)	$ 16,816

XML

Rate and Regulatory Matters - Summary of status of updates for previous two years for various rate riders (Details 1) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 214,117	$ 206,242
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Public Utilities, General Disclosures [Line Items]
Annual Revenue	[1]	$ 1,966	2,506
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2016 Incentive and Cost Recovery
Public Utilities, General Disclosures [Line Items]
R - Request Date		Mar. 31, 2017
Effective Date Requested or Approved		Oct. 01, 2017
Annual Revenue		$ 9,868
Rate		$0.00754/kwh
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2015 Incentive and Cost Recovery
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Jul. 19, 2016
Effective Date Requested or Approved		Oct. 01, 2016
Annual Revenue		$ 8,590
Rate		$0.00275/kwh
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2014 Incentive and Cost Recovery
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Jul. 10, 2015
Effective Date Requested or Approved		Oct. 01, 2015
Annual Revenue		$ 8,689
Rate		$0.00287/kwh
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 2,170	2,276
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date	[2]	Jul. 05, 2016
Effective Date Requested or Approved	[2]	Sep. 01, 2016
Annual Revenue	[2]	$ 4,736
Rate	[2]	Various
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Mar. 09, 2016
Effective Date Requested or Approved		Apr. 01, 2016
Annual Revenue		$ 7,203
Rate		Various
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2014 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Feb. 18, 2015
Effective Date Requested or Approved		Mar. 01, 2015
Annual Revenue		$ 8,388
Rate		Various
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 2,824	3,082
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date	[2]	Jul. 05, 2016
Effective Date Requested or Approved	[2]	Sep. 01, 2016
Annual Revenue	[2]	$ 11,884
Rate	[2]	6.927% of Rev
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Mar. 09, 2016
Effective Date Requested or Approved		Oct. 01, 2015
Annual Revenue		$ 12,104
Rate		7.006% of Rev
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 1,770	2,059
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Mar. 15, 2017
Effective Date Requested or Approved		Apr. 01, 2017
Annual Revenue		$ 9,156
Rate		7.005% of Rev
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Jun. 22, 2016
Effective Date Requested or Approved		Jul. 01, 2016
Annual Revenue		$ 9,262
Rate		7.573% of Rev
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2014 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Mar. 25, 2015
Effective Date Requested or Approved		Apr. 01, 2015
Annual Revenue		$ 5,441
Rate		4.069% of Rev
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 2,511	2,236
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Dec. 14, 2016
Effective Date Requested or Approved		Jan. 01, 2017
Annual Revenue		$ 6,916
Rate		Various
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Dec. 16, 2015
Effective Date Requested or Approved		Jan. 01, 2016
Annual Revenue		$ 9,985
Rate		Various
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 2,488	2,811
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2017 Annual Update
Public Utilities, General Disclosures [Line Items]
R - Request Date		Mar. 31, 2017
Effective Date Requested or Approved		Jul. 01, 2017
Annual Revenue		$ 9,917
Rate		7.633% of base
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Jun. 22, 2016
Effective Date Requested or Approved		Jul. 01, 2016
Annual Revenue		$ 10,359
Rate		7.904% of base
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Jun. 17, 2015
Effective Date Requested or Approved		Jul. 01, 2015
Annual Revenue		$ 12,249
Rate		9.193% of base
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 240	159
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 441	651
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Feb. 17, 2017
Effective Date Requested or Approved		Mar. 01, 2017
Annual Revenue		$ 2,053
Rate		Various
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Feb. 12, 2016
Effective Date Requested or Approved		Mar. 01, 2016
Annual Revenue		$ 1,895
Rate		Various
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2014 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Feb. 13, 2015
Effective Date Requested or Approved		Mar. 01, 2015
Annual Revenue		$ 1,538
Rate		Various
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Annual Revenue		$ 597	$ 633
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | 2016 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Oct. 26, 2016
Effective Date Requested or Approved		Nov. 01, 2016
Annual Revenue		$ 2,238
Rate		$0.00536/kwh
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | 2015 Annual Update
Public Utilities, General Disclosures [Line Items]
A - Approval Date		Oct. 15, 2015
Effective Date Requested or Approved		Nov. 01, 2015
Annual Revenue		$ 2,728
Rate		$0.00643/kwh

[1] Includes MNCIP costs recovered in base rates.

[2] Approved on a provisional basis and subject to change based on comments from the MNDOC.

XML

Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 2) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		$ 214,117	$ 206,242
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders	[1]	1,966	2,506
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		2,170	2,276
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		2,824	3,082
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		1,770	2,059
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		2,511	2,236
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		2,488	2,811
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		240	159
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		441	651
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider
Public Utilities, General Disclosures [Line Items]
Revenues recorded under rate riders		$ 597	$ 633

[1] Includes MNCIP costs recovered in base rates.

XML

Rate and Regulatory Matters (Detail Textuals) - Otter Tail Power Company $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) kV mi
Big Stone South - Brookings MVP
Public Utilities, General Disclosures [Line Items]
Project costs incurred to date | $	$ 64.0
Percentage of assets of project	100.00%
Expanded capacity of projects | kV	345
Extended distance of transmission line | mi	70
Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission
Public Utilities, General Disclosures [Line Items]
Project costs incurred to date | $	$ 57.9
Percentage of assets of project	100.00%
Expanded capacity of projects | kV	345
Extended distance of transmission line | mi	163

XML

Rate and Regulatory Matters (Detail Textuals 1) $ in Millions		1 Months Ended		3 Months Ended
	Apr. 14, 2016	Feb. 16, 2016	Apr. 25, 2011 USD ($)	Mar. 31, 2017 USD ($) Customer	May 25, 2016
Otter Tail Power Company | 2016 General Rate Case | Rebuttal Testimony
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				10.05%
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program
Public Utilities, General Disclosures [Line Items]
Incentives net benefit, 2017					13.50%
Incentives net benefit, 2018					12.00%
Incentives net benefit, 2019					10.00%
Assumed savings of utility					1.70%
Percentage of reduction in financial incentive					50.00%
Number of large customers who requests for exemption | Customer				2
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014
Public Utilities, General Disclosures [Line Items]
Financial incentive request approved				$ 3.0
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2015
Public Utilities, General Disclosures [Line Items]
Financial incentive request approved				4.3
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2016
Public Utilities, General Disclosures [Line Items]
Amount of financial incentive requested				5.0
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case
Public Utilities, General Disclosures [Line Items]
General rate revenue increase requested			$ 5.0
Percentage of increase in base rate revenue requested			1.60%
Public utilities allowed rate of return on rate base prior to approval of increase in base rate			8.33%
Public utilities allowed rate of return on rate base subsequent to approval of increase in base rate			8.61%
Public utilities allowed rate of return on equity prior to approval of increase in base rate			10.43%
Public utilities allowed rate of return on equity subsequent to approval of increase in base rate			10.74%
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case
Public Utilities, General Disclosures [Line Items]
Public utilities allowed rate of return on rate base		8.07%
Public utilities allowed rate of return on equity increase in base rate		10.40%
Percentage of capital		52.50%
Authorized a revenue increase				$ 12.3
Increase in base rate revenue				6.27%
Approved interim rate increase	9.56%			9.56%
Allowed rate of return on equity				9.41%
Rate of return of long term debt in percentage				47.50%
Rate of return of equity capital in percentage				52.50%
Amount of estimated interim rate refund				$ 5.2
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Minimum
Public Utilities, General Disclosures [Line Items]
Decrease in allowed rate of return on rate base				7.5056%
Decrease in allowed rate of return on equity				9.41%
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Maximum
Public Utilities, General Disclosures [Line Items]
Decrease in allowed rate of return on rate base				8.61%
Decrease in allowed rate of return on equity				10.74%
MNDOC | 2016 General Rate Case | Direct Testimony
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				8.87%
MNDOC | 2016 General Rate Case | Rebuttal Testimony
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				8.66%
OAG | 2016 General Rate Case | Direct Testimony
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				6.96%
OAG | 2016 General Rate Case | Rebuttal Testimony
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				7.14%
ALJ | 2016 General Rate Case
Public Utilities, General Disclosures [Line Items]
Percentage of allowed rate of return on equity				9.54%

XML

Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - 2010 General Rate Case $ in Millions	Nov. 25, 2009 USD ($)
Public Utilities, General Disclosures [Line Items]
Revenue increase approved by rate authority	$ 3.6
Percentage of increase in base rate revenue requested	3.00%
Percentage of allowed rate of return on rate base	8.62%
Percentage of allowed rate of return on equity	10.75%

XML

Rate and Regulatory Matters (Detail Textuals 3) - USD ($)				1 Months Ended				3 Months Ended
	Feb. 12, 2015	Nov. 06, 2014	Nov. 12, 2013	Sep. 28, 2016	Jun. 30, 2016	Dec. 22, 2015	Apr. 21, 2011	Mar. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities								$ 88,022,000	$ 85,727,000
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case
Public Utilities, General Disclosures [Line Items]
Revenue increase approved by rate authority							$ 643,000
Percentage of increase in base rate revenue requested							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 | Federal Energy Regulatory Commission
Public Utilities, General Disclosures [Line Items]
Current return on equity used in transmission rates			12.38%		9.70%	10.32%
Proposed reduced return on equity used in transmission rates	8.67%		9.15%
Additional incentive basis point		50-basis points
Expected percentage of return on equity				10.82%
Expected percentage of return on equity, description				ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder)
Percentage of refund processed								90.00%
Regulatory liabilities								$ 1,700,000	$ 2,700,000

XML

Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands		3 Months Ended	12 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current		$ 17,973	$ 21,297
Regulatory Liabilities - Current		5,706	3,294
Net Regulatory Asset Position - Current		12,267	18,003
Regulatory Assets - Long -Term		128,968	132,094
Regulatory Liabilities - Long -Term		82,316	82,433
Net Regulatory Asset Position - Long-Term		46,652	49,661
Regulatory Assets - Total		146,941	153,391
Regulatory Liabilities - Total		88,022	85,727
Net Regulatory Asset Position		58,919	67,664
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	6,443	6,443
Regulatory Assets - Long -Term	[1]	106,656	108,267
Regulatory Assets - Total	[1]	$ 113,099	$ 114,710
Regulatory Assets - Remaining Recovery/Refund Period	[1]	see below	see below
Deferred Marked-to-Market Losses
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 4,063	$ 4,063
Regulatory Assets - Long -Term	[1]	5,452	6,467
Regulatory Assets - Total	[1]	$ 9,515	$ 10,530
Regulatory Assets - Remaining Recovery/Refund Period	[1]	45 months	48 months
Conservation Improvement Program Costs and Incentives
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 3,745	$ 4,836
Regulatory Assets - Long -Term	[2]	5,735	5,158
Regulatory Assets - Total	[2]	$ 9,480	$ 9,994
Regulatory Assets - Remaining Recovery/Refund Period	[2]	30 months	21 months
Accumulated ARO Accretion/Depreciation Adjustment
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]
Regulatory Assets - Long -Term	[1]	6,276	6,153
Regulatory Assets - Total	[1]	$ 6,276	$ 6,153
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Big Stone II Unrecovered Project Costs - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 739	$ 778
Regulatory Assets - Long -Term	[1]	1,926	2,087
Regulatory Assets - Total	[1]	$ 2,665	$ 2,865
Regulatory Assets - Remaining Recovery/Refund Period	[1]	49 months	52 months
Recoverable Fuel and Purchased Power Costs
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]		$ 1,798
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]		$ 1,798
Regulatory Assets - Remaining Recovery/Refund Period			12 months
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 301	$ 325
Regulatory Assets - Long -Term	[1]	1,150	1,214
Regulatory Assets - Total	[1]	$ 1,451	$ 1,539
Regulatory Assets - Remaining Recovery/Refund Period	[1]	186 months	189 months
Deferred Income Taxes
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]
Regulatory Liabilities - Current
Regulatory Assets - Long -Term	[1]	1,020	1,014
Regulatory Liabilities - Long -Term		785	818
Regulatory Assets - Total	[1]	1,020	1,014
Regulatory Liabilities - Total		$ 785	$ 818
Regulatory Assets - Remaining Recovery/Refund Period	[1]	asset lives	asset lives
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Minnesota Deferred Rate Case Expenses Subject to Recovery
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[1]	$ 954	$ 1,082
Regulatory Assets - Long -Term	[1]
Regulatory Assets - Total	[1]	$ 954	$ 1,082
Regulatory Assets - Remaining Recovery/Refund Period	[1]	12 months	12 months
North Dakota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 727	$ 1,319
Regulatory Assets - Long -Term	[2]	62	482
Regulatory Assets - Total	[2]	$ 789	$ 1,801
Regulatory Assets - Remaining Recovery/Refund Period	[2]	24 months	15 months
Big Stone II Unrecovered Project Costs - South Dakota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 100	$ 100
Regulatory Assets - Long -Term	[2]	517	543
Regulatory Assets - Total	[2]	$ 617	$ 643
Regulatory Assets - Remaining Recovery/Refund Period	[2]	74 months	77 months
North Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 426
Regulatory Assets - Long -Term	[2]	59	568
Regulatory Assets - Total	[2]	$ 485	$ 568
Regulatory Assets - Remaining Recovery/Refund Period	[2]	21 months	24 months
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 251	$ 333
Regulatory Liabilities - Current		33
Regulatory Assets - Long -Term	[2]	115
Regulatory Liabilities - Long -Term		99	132
Regulatory Assets - Total	[2]	366	333
Regulatory Liabilities - Total		$ 132	$ 132
Regulatory Assets - Remaining Recovery/Refund Period	[2]	21 months	12 months
Regulatory Liabilities - Remaining Recovery/Refund Period		21 months	24 months
South Dakota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 106	$ 73
Regulatory Assets - Long -Term	[2]		141
Regulatory Assets - Total	[2]	$ 106	$ 214
Regulatory Assets - Remaining Recovery/Refund Period	[2]	11 months	14 months
North Dakota Environmental Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]		$ 113
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]		$ 113
Regulatory Assets - Remaining Recovery/Refund Period	[2]		12 months
Minnesota Transmission Cost Recovery Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 95
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 95
Regulatory Assets - Remaining Recovery/Refund Period	[2]	12 months
Minnesota Renewable Resource Rider Accrued Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets - Current	[2]	$ 23	$ 34
Regulatory Assets - Long -Term	[2]
Regulatory Assets - Total	[2]	$ 23	$ 34
Regulatory Assets - Remaining Recovery/Refund Period	[2]	6 months	9 months
Accumulated Reserve for Estimated Removal Costs - Net of Salvage
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current
Regulatory Liabilities - Long -Term		81,314	80,404
Regulatory Liabilities - Total		$ 81,314	$ 80,404
Regulatory Liabilities - Remaining Recovery/Refund Period		asset lives	asset lives
Refundable Fuel Clause Adjustment Revenues
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 2,119
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 2,119
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
North Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 1,545	$ 1,381
Regulatory Liabilities - Long -Term			782
Regulatory Liabilities - Total		$ 1,545	$ 2,163
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	24 months
Revenue for Rate Case expenses Subject to Refund - Minnesota
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 711	$ 711
Regulatory Liabilities - Long -Term		30	208
Regulatory Liabilities - Total		$ 741	$ 919
Regulatory Liabilities - Remaining Recovery/Refund Period		13 months	16 months
Minnesota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 631	$ 139
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 631	$ 139
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
South Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 354	$ 285
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 354	$ 285
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months	12 months
North Dakota Environmental Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 299
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 299
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
South Dakota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 8
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total		$ 8
Regulatory Liabilities - Remaining Recovery/Refund Period		12 months
Minnesota Transmission Cost Recovery Rider Accrued Refund
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current			$ 757
Regulatory Liabilities - Long -Term
Regulatory Liabilities - Total			$ 757
Regulatory Liabilities - Remaining Recovery/Refund Period			12 months
Other
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities - Current		$ 6	$ 21
Regulatory Liabilities - Long -Term		88	89
Regulatory Liabilities - Total		$ 94	$ 110
Regulatory Liabilities - Remaining Recovery/Refund Period		201 months	204 months

[1] Costs subject to recovery without a rate of return.

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

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Regulatory Assets and Liabilities (Detail Textuals)	3 Months Ended
	Mar. 31, 2017
Debt Reacquisition Premiums
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory assets - long term, remaining recovery/refund period	186 months

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Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details) - Legally enforceable netting arrangements - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements	(14,590)	(17,382)
Net Balance Subject to Legally Enforceable Netting Arrangements	$ (14,590)	$ (17,382)

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Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Current Liability - Marked-to-Market Loss (in thousands)
Loss Contracts Covered by Deposited Funds or Letters of Credit
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	14,590	17,382
Total Loss Contracts based on Current Market Values		$ 14,590	$ 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 $14,590 $17,382 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $14,590 $17,382

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Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parentheticals) (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands		Mar. 31, 2017	Dec. 31, 2016
Credit Derivatives [Line Items]
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade	[1]	$ 14,590	$ 17,382
Offsetting Gains with Counterparties under Master Netting Agreements
Reporting Date Deposit Requirement if Credit Risk Feature Triggered		$ 14,590	$ 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 $14,590 $17,382 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $14,590 $17,382

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2016	$ 670,104
Common Stock Issuances, Net of Expenses	2,564
Common Stock Retirements	(1,759)
Net Income	19,585	$ 14,520
Other Comprehensive Income	105
Employee Stock Incentive Plans Expense	1,150
Common Dividends ($0.32 per share)	(12,626)
Balance, March 31, 2017	679,123
Par Value, Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2016	196,741
Common Stock Issuances, Net of Expenses	837
Common Stock Retirements	(234)
Balance, March 31, 2017	197,344
Premium on Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2016	337,684
Common Stock Issuances, Net of Expenses	1,727
Common Stock Retirements	(1,525)
Employee Stock Incentive Plans Expense	1,150
Balance, March 31, 2017	339,036
Retained Earnings
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2016	139,479
Net Income	19,585
Common Dividends ($0.32 per share)	(12,626)
Balance, March 31, 2017	146,438
Accumulated Other Comprehensive Income/(Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance, December 31, 2016	(3,800)
Other Comprehensive Income	105
Balance, March 31, 2017	$ (3,695)

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parentheticals) (Details) - $ / shares	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]
Dividends Declared Per Common Share (in dollars per share)	$ 0.3200	$ 0.3125

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1)	3 Months Ended
	Mar. 31, 2017 shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
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	36,320
Cash Invested	11,750
Employee Stock Ownership Plan	14,835
Vesting of Restricted Stock Units	9,975
Employee Stock Purchase Plan:
Cash Invested
Dividends Reinvested	5,131
Retirements:
Shares Withheld for Individual Income Tax Requirements	(46,634)
Common Shares Outstanding, March 31, 2017	39,468,804

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted (Details 2) - shares	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Stockholders Equity and Earnings Per Share [Abstract]
Weighted Average Common Shares Outstanding - Basic	39,350,802	37,936,943
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	201,639	46,885
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees	57,873	39,841
Nonvested Restricted Shares	27,069	17,776
Shares Expected to be Issued Under the Deferred Compensation Program for Directors	3,342	3,763
Total Dilutive Shares	289,923	108,265
Weighted Average Common Shares Outstanding - Diluted	39,640,725	38,045,208

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Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	May 11, 2015
Stockholders Equity Note [Line Items]
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations	$ 0.01	$ 0.01
Distribution Agreement | J.P. Morgan Securities (JPMS)
Stockholders Equity Note [Line Items]
Aggregate sales price			$ 75

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Share-Based Payments - Stock incentive awards to executive officers (Details)	3 Months Ended
	Mar. 31, 2017 $ / shares shares
Restricted Stock Units | Through February 6, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted | shares	15,900
Grant-Date Fair Value per Award | $ / shares	$ 37.65
Vesting Percentage	25.00%
Vesting Date	February 6, 2021
Stock Performance Awards | December 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units Granted | shares	59,500
Grant-Date Fair Value per Award | $ / shares	$ 31.00
Vesting Date	December 31, 2019

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Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details 1) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	$ 1,150	$ 1,026
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	649	537
Restricted Stock Units | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	264	245
Restricted Stock Units | Non-Executive Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	87	64
Restricted Stock | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	22	29
Restricted Stock | Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense	128	107
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense		$ 44

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Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details 1)	3 Months Ended
	Mar. 31, 2016
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation expense, discount rate	15.00%

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Share-Based Payments (Detail Textuals) $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to stock-based compensation | $	$ 5.3
Weighted-average period of amortization	2 years 3 months 18 days
Stock Performance Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award	59,500
Stock Performance Awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of target amount as actual payment	0.00%
Stock Performance Awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate common shares award	89,250
Percentage of target amount as actual payment	150.00%
Stock Performance Awards | Executive Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Targeted aggregate common shares award total shareholder return component	39,667
Targeted aggregate common shares award return on equity component	19,833
Period specified for average adjusted return	3 years

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Retained Earnings Restriction (Detail Textuals) - USD ($)	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Retained Earnings Restriction [Line Items]
Total Capitalization	$ 1,169,495,000	$ 1,175,445,000
OTP
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	52.90%
Net assets restricted from distribution	$ 443,000,000
OTP | Minimum
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	47.50%
OTP | Maximum
Retained Earnings Restriction [Line Items]
Equity to total capitalization ratio	58.10%
Total Capitalization	$ 1,123,168,000

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Commitments and Contingencies (Detail Textuals) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017 USD ($) Utility	Dec. 31, 2016 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Loss contingency, range of possible loss, maximum	$ 1.0
Otter Tail Power Company
Commitments and Contingencies Disclosure [Line Items]
Number of utilities, generators and power marketers | Utility	200
Otter Tail Power Company | Construction Programs
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$ 114.6	$ 84.8
Otter Tail Power Company | Coal Purchase Commitments
Commitments and Contingencies Disclosure [Line Items]
Commitment under contracts aggregate amount	$ 3.0
Contracts expiration year	2019 and 2040
Otter Tail Power Company | Federal Energy Regulatory Commission
Commitments and Contingencies Disclosure [Line Items]
Estimated liability of refund obligation	$ 1.7	$ 2.7
Percentage of refund processed of FERC-ordered reduction in MISO Tariff allowed ROE	90.00%

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Short-Term and Long-Term Borrowings - Status of lines of credit (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Line Limit	$ 300,000
In Use	59,176
Restricted due to Outstanding Letters of Credit	50
Available	240,774	$ 257,067
Otter Tail Corporation Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	130,000
In Use	12,825
Restricted due to Outstanding Letters of Credit
Available	117,175	130,000
OTP Credit Agreement
Line of Credit Facility [Line Items]
Line Limit	170,000
In Use	46,351
Restricted due to Outstanding Letters of Credit	50
Available	$ 123,599	$ 127,067

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Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Short-Term Debt	$ 59,176	$ 42,883
Long-Term Debt	537,885	540,942
Less: Current Maturities net of Unamortized Debt Issuance Costs	45,192	33,201
Unamortized Long-Term Debt Issuance Costs	2,321	2,400
Total Long-Term Debt net of Unamortized Debt Issuance Costs	490,372	505,341
Total Short-Term and Long-Term Debt (with current maturities)	594,740	581,425
Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	12,000	15,000
3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt	80,000	80,000
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000	60,000
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000	90,000
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	86	106
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	799	836
OTP
Debt Instrument [Line Items]
Short-Term Debt	46,351	42,883
Long-Term Debt	445,000	445,000
Less: Current Maturities net of Unamortized Debt Issuance Costs	32,981	32,970
Unamortized Long-Term Debt Issuance Costs	1,801	1,861
Total Long-Term Debt net of Unamortized Debt Issuance Costs	410,218	410,169
Total Short-Term and Long-Term Debt (with current maturities)	489,550	486,022
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt	33,000	33,000
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt	140,000	140,000
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt	30,000	30,000
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt	42,000	42,000
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt	60,000	60,000
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt	50,000	50,000
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt	90,000	90,000
Otter Tail Corporation
Debt Instrument [Line Items]
Short-Term Debt	12,825
Long-Term Debt	92,885	95,942
Less: Current Maturities net of Unamortized Debt Issuance Costs	12,211	231
Unamortized Long-Term Debt Issuance Costs	520	539
Total Long-Term Debt net of Unamortized Debt Issuance Costs	80,154	95,172
Total Short-Term and Long-Term Debt (with current maturities)	105,190	95,403
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt	12,000	15,000
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt	80,000	80,000
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt	86	106
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt	$ 799	$ 836

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Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details 1)	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	0.90%	0.90%
Long-Term Debt, Due Date	Feb. 05, 2018	Feb. 05, 2018
3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018	Apr. 01, 2018
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.95%	5.95%
Long-Term Debt, Due Date	Aug. 20, 2017	Aug. 20, 2017
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.63%	4.63%
Long-Term Debt, Due Date	Dec. 01, 2021	Dec. 01, 2021
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.15%	6.15%
Long-Term Debt, Due Date	Aug. 20, 2022	Aug. 20, 2022
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.37%	6.37%
Long-Term Debt, Due Date	Aug. 20, 2027	Aug. 20, 2027
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	4.68%	4.68%
Long-Term Debt, Due Date	Feb. 27, 2029	Feb. 27, 2029
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	6.47%	6.47%
Long-Term Debt, Due Date	Aug. 20, 2037	Aug. 20, 2037
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	5.47%	5.47%
Long-Term Debt, Due Date	Feb. 27, 2044	Feb. 27, 2044
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	0.90%	0.90%
Long-Term Debt, Due Date	Feb. 05, 2018	Feb. 05, 2018
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.55%	3.55%
Long-Term Debt, Due Date	Dec. 15, 2026	Dec. 15, 2026
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	3.95%	3.95%
Long-Term Debt, Due Date	Apr. 01, 2018	Apr. 01, 2018
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
Debt Instrument [Line Items]
Long-Term Debt, Interest Rate	2.54%	2.54%
Long-Term Debt, Due Date	Mar. 18, 2021	Mar. 18, 2021

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Short-Term and Long-Term Borrowings (Detail Textuals) - Term Loan Agreement - USD ($) $ in Millions		3 Months Ended
	Feb. 05, 2016	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Borrowed amount	$ 50.0
Interest rate base	30 day LIBOR plus 0.90%
Description of variable rate basis	LIBOR
Basis spread on variable rate	0.90%
Repayment of debt		$ 3.0	$ 35.0

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Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		$ 1,407	$ 1,382
Interest Cost on Projected Benefit Obligation		3,534	3,522
Expected Return on Assets		(4,807)	(4,867)
Amortization of Prior-Service Cost:
From Regulatory Asset		30	47
From Other Comprehensive Income	[1]	1	1
Amortization of Net Actuarial Loss:
From Regulatory Asset		1,273	1,227
From Other Comprehensive Income	[1]	31	31
Net Periodic Pension Cost		1,469	1,343
Executive Survivor and Supplemental Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		73	63
Interest Cost on Projected Benefit Obligation		422	417
Amortization of Prior-Service Cost:
From Regulatory Asset		4	4
From Other Comprehensive Income	[2]	9	9
Amortization of Net Actuarial Loss:
From Regulatory Asset		71	73
From Other Comprehensive Income	[3]	110	112
Net Periodic Pension Cost		689	678
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service Cost - Benefit Earned During the Period		356	306
Interest Cost on Projected Benefit Obligation		678	541
Amortization of Prior-Service Cost:
From Regulatory Asset			33
From Other Comprehensive Income	[1]		1
Amortization of Net Actuarial Loss:
From Regulatory Asset		233
From Other Comprehensive Income	[1]	6
Net Periodic Pension Cost		1,273	881
Effect of Medicare Part D Subsidy		$ (140)	$ (257)

[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 $ 4 Other Nonelectric Expenses 5 5

[3] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44

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Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) - Executive Survivor and Supplemental Retirement Plan - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:	[1]	$ 9	$ 9
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:	[2]	110	112
Electric Operation and Maintenance Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:		4	4
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:		66	68
Other Nonelectric Expenses
Defined Benefit Plan Disclosure [Line Items]
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:		5	5
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:		$ 44	$ 44

[1] Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 4 Other Nonelectric Expenses 5 5

[2] Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44

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Pension Plan and Other Postretirement Benefits (Detail Textuals) $ in Millions	1 Months Ended
	Jan. 31, 2016 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discretionary plan contributions	$ 10.0

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Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Carrying Amount
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	$ (59,176)	$ (42,883)
Long-Term Debt including Current Maturities	(535,564)	(538,542)
Fair Value
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Short-Term Debt	(59,176)	(42,883)
Long-Term Debt including Current Maturities	$ (582,743)	$ (583,835)

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Fair Value of Financial Instruments (Detail Textuals)	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Otter Tail Corporation Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Line of credit facility, description of variable rate basis	LIBOR	LIBOR
Basis spread on variable rate	1.75%	1.75%
OTP Credit Agreement
Fair Value Of Financial Instruments [Line Items]
Line of credit facility, description of variable rate basis	LIBOR	LIBOR
Basis spread on variable rate	1.25%	1.25%

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Income Tax Expense - Continuing Operations - Effective income tax rate (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Before Income Taxes - Continuing Operations	$ 25,892	$ 19,982
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%)	10,098	7,793
Increases (Decreases) in Tax from:
Federal Production Tax Credits	(2,052)	(1,686)
Excess Tax Deduction - 2014 Performance Share Awards	(697)
Section 199 Domestic Production Activities Deduction	(330)	(104)
Corporate Owned Life Insurance	(294)	(92)
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes	(212)	(212)
Employee Stock Ownership Plan Dividend Deduction	(172)	(158)
Other Items - Net	22	(49)
Income Tax Expense - Continuing Operations	$ 6,363	$ 5,492
Effective Income Tax Rate - Continuing Operations	24.60%	27.50%

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Income Tax Expense - Continuing Operations - Effective income tax rate (Parentheticals) (Details)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Composite Federal and State Statutory Rate	39.00%	39.00%

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Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance on January 1	$ 891	$ 468
Increases Related to Tax Positions for Prior Years
Increases Related to Tax Positions for Current Year	43	16
Uncertain Positions Resolved During Year
Balance on March 31	$ 934	$ 484

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Discontinued Operations - Warranty Reserves (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Movement in Standard Product Warranty Accrual [Roll Forward]
Warranty Reserve Balance, January 1	$ 1,369	$ 2,103
Additional Provision for Warranties Made During the Year
Settlements Made During the Year	(1)
Decrease in Warranty Estimates for Prior Years	(100)
Warranty Reserve Balance, March 31	$ 1,268	$ 2,103

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Discontinued Operations (Detail Textuals)	3 Months Ended
	Mar. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Warranty period for certain products sold	one to fifteen year warranties