Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 31, 2016 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Otter Tail Corp | |
Entity Central Index Key | 1,466,593 | |
Trading Symbol | ottr | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock Shares Outstanding | 39,268,205 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2016 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 |
Consolidated Balance Sheets (no
Consolidated Balance Sheets (not audited) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and Cash Equivalents | ||
Accounts Receivable: | ||
Trade - Net | 69,556 | 62,974 |
Other | 7,082 | 9,073 |
Inventories | 80,848 | 85,416 |
Unbilled Revenues | 14,882 | 17,869 |
Income Taxes Receivable | 4,000 | |
Regulatory Assets | 19,958 | 18,904 |
Other | 11,139 | 8,453 |
Assets of Discontinued Operations | 249 | |
Total Current Assets | 203,714 | 206,689 |
Investments | 8,065 | 8,284 |
Other Assets | 33,707 | 32,784 |
Goodwill | 37,572 | 39,732 |
Other Intangibles - Net | 15,291 | 15,673 |
Regulatory Assets | 118,123 | 127,707 |
Plant | ||
Electric Plant in Service | 1,842,931 | 1,820,763 |
Nonelectric Operations | 215,074 | 201,343 |
Construction Work in Progress | 143,999 | 79,612 |
Total Gross Plant | 2,202,004 | 2,101,718 |
Less Accumulated Depreciation and Amortization | 749,569 | 713,904 |
Net Plant | 1,452,435 | 1,387,814 |
Total Assets | 1,868,907 | 1,818,683 |
Current Liabilities | ||
Short-Term Debt | 37,173 | 80,672 |
Current Maturities of Long-Term Debt | 85,490 | 52,422 |
Accounts Payable | 77,704 | 89,499 |
Accrued Salaries and Wages | 15,573 | 16,182 |
Accrued Taxes | 12,635 | 14,827 |
Other Accrued Liabilities | 16,050 | 15,416 |
Liabilities of Discontinued Operations | 1,631 | 2,098 |
Total Current Liabilities | 246,256 | 271,116 |
Pensions Benefit Liability | 95,653 | 104,912 |
Other Postretirement Benefits Liability | 49,718 | 48,730 |
Other Noncurrent Liabilities | 25,857 | 23,854 |
Commitments and Contingencies (note 9) | ||
Deferred Credits | ||
Deferred Income Taxes | 222,244 | 207,669 |
Deferred Tax Credits | 23,264 | 24,506 |
Regulatory Liabilities | 79,835 | 77,432 |
Other | 8,604 | 11,595 |
Total Deferred Credits | 333,947 | 321,202 |
Capitalization | ||
Long-Term Debt - Net | 460,757 | 443,846 |
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2016-39,224,553 Shares; 2015-37,857,186 Shares | 196,123 | 189,286 |
Premium on Common Shares | 329,288 | 293,610 |
Retained Earnings | 134,884 | 126,025 |
Accumulated Other Comprehensive Loss | (3,576) | (3,898) |
Total Common Equity | 656,719 | 605,023 |
Total Capitalization | 1,117,476 | 1,048,869 |
Total Liabilities and Equity | 1,868,907 | 1,818,683 |
Cumulative Preferred Shares | ||
Capitalization | ||
Cumulative Shares | ||
Cumulative Preference Shares | ||
Capitalization | ||
Cumulative Shares |
Consolidated Balance Sheets (n3
Consolidated Balance Sheets (not audited) (Parentheticals) - $ / shares | Sep. 30, 2016 | Dec. 31, 2015 |
Common shares, par value (in dollars per share) | $ 5 | $ 5 |
Common shares, authorized | 50,000,000 | 50,000,000 |
Common shares, outstanding | 39,224,553 | 37,857,186 |
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 |
Consolidated Statements of Inco
Consolidated Statements of Income (not audited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Operating Revenues | ||||
Electric | $ 102,712 | $ 100,538 | $ 313,615 | $ 304,998 |
Product Sales | 94,463 | 99,485 | 293,284 | 286,019 |
Total Operating Revenues | 197,175 | 200,023 | 606,899 | 591,017 |
Operating Expenses | ||||
Production Fuel - Electric | 14,789 | 11,124 | 40,479 | 29,906 |
Purchased Power - Electric System Use | 11,473 | 18,725 | 43,486 | 62,101 |
Electric Operation and Maintenance Expenses | 36,207 | 32,648 | 115,206 | 107,929 |
Cost of Products Sold (depreciation included below) | 75,405 | 78,428 | 228,993 | 224,912 |
Other Nonelectric Expenses | 10,197 | 10,771 | 30,890 | 32,057 |
Depreciation and Amortization | 18,314 | 15,141 | 55,128 | 44,337 |
Property Taxes - Electric | 3,506 | 3,560 | 10,774 | 10,324 |
Total Operating Expenses | 169,891 | 170,397 | 524,956 | 511,566 |
Operating Income | 27,284 | 29,626 | 81,943 | 79,451 |
Interest Charges | 8,026 | 7,730 | 23,996 | 23,175 |
Other Income | 499 | 334 | 2,431 | 1,473 |
Income Before Income Taxes - Continuing Operations | 19,757 | 22,230 | 60,378 | 57,749 |
Income Tax Expense - Continuing Operations | 5,163 | 6,521 | 15,738 | 14,602 |
Net Income from Continuing Operations | 14,594 | 15,709 | 44,640 | 43,147 |
Discontinued Operations | ||||
Income (Loss) - net of Income Tax Expense (Benefit) of $14, ($168), $114 and ($2,873) for the respective periods | 22 | (252) | 171 | (4,316) |
Impairment Loss - net of Income Tax Benefit of$0 for the nine months ended September 30, 2015 | (1,000) | |||
(Loss) Gain on Disposition - net of Income Tax (Benefit) Expense of ($43) and $4,493 for the three and nine months ended September 30, 2015 | (65) | 6,932 | ||
Net Income (Loss) from Discontinued Operations | 22 | (317) | 171 | 1,616 |
Net Income | $ 14,616 | $ 15,392 | $ 44,811 | $ 44,763 |
Average Number of Common Shares Outstanding - Basic | 38,832,659 | 37,575,413 | 38,316,324 | 37,417,283 |
Average Number of Common Shares Outstanding - Diluted | 39,005,706 | 37,794,543 | 38,457,401 | 37,636,413 |
Basic Earnings (Loss) Per Common Share: | ||||
Continuing Operations (in dollars per share) | $ 0.38 | $ 0.42 | $ 1.17 | $ 1.15 |
Discontinued Operations (in dollars per share) | (0.01) | 0.05 | ||
Earnings Per Share, Basic, Total (in dollars per share) | 0.38 | 0.41 | 1.17 | 1.20 |
Diluted Earnings (Loss) Per Common Share: | ||||
Continuing Operations (in dollars per share) | 0.37 | 0.42 | 1.16 | 1.15 |
Discontinued Operations (in dollars per share) | (0.01) | 0.01 | 0.04 | |
Earnings Per Share, Diluted, Total (in dollars per share) | 0.37 | 0.41 | 1.17 | 1.19 |
Dividends Declared Per Common Share (in dollars per share) | $ 0.3125 | $ 0.3075 | $ 0.9375 | $ 0.9225 |
Consolidated Statements of Inc5
Consolidated Statements of Income (not audited) (Parentheticals) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Statement [Abstract] | ||||
Income tax expense (benefit) on income (loss) from discontinued operation | $ 14 | $ (168) | $ 114 | $ (2,873) |
Income tax (benefit) expense on impairment | 0 | |||
Income tax (benefit) expense on gain (loss) from disposition | $ (43) | $ 4,493 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (not audited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement Of Income and Comprehensive Income [Abstract] | ||||
Net Income | $ 14,616 | $ 15,392 | $ 44,811 | $ 44,763 |
Unrealized Gain on Available-for-Sale Securities: | ||||
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period | (3) | (3) | (3) | |
(Losses) Gains Arising During Period | (35) | 6 | 65 | 1 |
Income Tax Benefit (Expense) | 13 | (2) | (22) | 1 |
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax | (25) | 4 | 40 | (1) |
Pension and Postretirement Benefit Plans: | ||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 161 | 205 | 470 | 616 |
Income Tax Expense | (64) | (82) | (188) | (247) |
Pension and Postretirement Benefit Plans - net-of-tax | 97 | 123 | 282 | 369 |
Total Other Comprehensive Income | 72 | 127 | 322 | 368 |
Total Comprehensive Income | $ 14,688 | $ 15,519 | $ 45,133 | $ 45,131 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (not audited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Cash Flows from Operating Activities | ||
Net Income | $ 44,811 | $ 44,763 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Net Gain from Sale of Discontinued Operations | (6,932) | |
Net (Income) Loss from Discontinued Operations | (171) | 5,316 |
Depreciation and Amortization | 55,128 | 44,337 |
Deferred Tax Credits | (1,242) | (1,408) |
Deferred Income Taxes | 14,924 | 12,244 |
Change in Deferred Debits and Other Assets | 5,595 | 13,839 |
Discretionary Contribution to Pension Plan | (10,000) | (10,000) |
Change in Noncurrent Liabilities and Deferred Credits | 5,999 | 4,345 |
Allowance for Equity/Other Funds Used During Construction | (605) | (944) |
Change in Derivatives Net of Regulatory Deferral | (28) | |
Stock Compensation Expense - Equity Awards | 1,151 | 1,428 |
Other - Net | (73) | (27) |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (3,490) | (14,020) |
Change in Inventories | 4,766 | 5,721 |
Change in Other Current Assets | 1,690 | 2,163 |
Change in Payables and Other Current Liabilities | (5,945) | (17,490) |
Change in Interest and Income Taxes Receivable/Payable | 2,538 | (1,499) |
Net Cash Provided by Continuing Operations | 115,076 | 81,808 |
Net Cash Used for Discontinued Operations | (333) | (11,581) |
Net Cash Provided by Operating Activities | 114,743 | 70,227 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (125,913) | (115,321) |
Net Proceeds from Disposal of Noncurrent Assets | 4,167 | 2,956 |
Purchase Price Adjustment (Payment) - BTD-Georgia Acquisition | 1,500 | (30,806) |
Cash Used for Investments and Other Assets | (3,161) | (7,297) |
Net Cash Used in Investing Activities - Continuing Operations | (123,407) | (150,468) |
Net Proceeds from Sale of Discontinued Operations | 32,765 | |
Net Cash Used in Investing Activities - Discontinued Operations | (1,769) | |
Net Cash Used in Investing Activities | (123,407) | (119,472) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | (841) | (1,236) |
Net Short-Term Debt (Repayments) Borrowings | (43,499) | 76,098 |
Proceeds from Issuance of Common Stock - net of Issuance Expenses | 39,378 | 10,979 |
Payments for Retirement of Capital Stock | (104) | (1,596) |
Proceeds from Issuance of Long-Term Debt | 50,000 | |
Short-Term and Long-Term Debt Issuance Expenses | (157) | (7) |
Payments for Retirement of Long-Term Debt | (161) | (149) |
Dividends Paid and Other Distributions | (35,952) | (34,607) |
Net Cash Provided by Financing Activities - Continuing Operations | 8,664 | 49,482 |
Net Cash Provided by Financing Activities - Discontinued Operations | 321 | |
Net Cash Provided by Financing Activities | 8,664 | 49,803 |
Net Change in Cash and Cash Equivalents - Discontinued Operations | (10) | |
Net Change in Cash and Cash Equivalents | 548 | |
Cash and Cash Equivalents at Beginning of Period | ||
Cash and Cash Equivalents at End of Period | $ 548 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2016 | |
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. In the case of derivative instruments, such as Otter Tail Power Company’s (OTP) 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging 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 ASC Topic 820, Fair Value Measurements and Disclosures Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX). Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015: September 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,408 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 3,506 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 764 Total Assets $ 764 $ 7,914 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 49 Total Liabilities $ 49 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Forward Gasoline Purchase Contracts Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company Inventories Inventories consist of the following: September 30, December 31, (in thousands) 2016 2015 Finished Goods $ 21,888 $ 25,971 Work in Process 13,774 12,821 Raw Material, Fuel and Supplies 45,186 46,624 Total Inventories $ 80,848 $ 85,416 Goodwill and Other Intangible Assets On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The newly acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2015 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table summarizes changes to goodwill by business segment during 2016: (in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2016 and December 31, 2015: September 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,577 $ 14,914 39-227 months Covenant not to Compete 590 213 377 23 months Total $ 23,081 $ 7,790 $ 15,291 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 348 $ 282 $ 1,103 $ 770 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099 Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,552 $ 21,760 Coyote Station Lignite Supply Agreement – Variable Interest Entity Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commenced with the initial delivery of coal to Coyote Station in May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. 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. Coyote Station started taking delivery of coal and paying for coal and the accumulated development fees and capital charges under the LSA in May 2016. OTP’s 35% share of the unrecovered development period costs, development fees and capital charges incurred by CCMC through September 30, 2016 is $61.7 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of September 30, 2016 could be as high as $61.7 million. New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) 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 September 30, 2016 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. The Company does not plan to adopt the updated guidance prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683 ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, ASU 2016-02 Leases (Topic 842) ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , |
Business Combinations and Segme
Business Combinations and Segment Information | 9 Months Ended |
Sep. 30, 2016 | |
Acquisition And Segment Information [Abstract] | |
Business Combinations and Segment Information | 2. Business Combinations and Segment Information Business Combinations On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business, operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was not material to the Company. Below is condensed balance sheet information disclosing the final allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia: (in thousands) Assets: Current Assets $ 4,906 Goodwill 6,083 Other Intangible Assets 6,270 Other Amortizable Assets 1,380 Fixed Assets 13,649 Total Assets $ 32,288 Liabilities: Current Liabilities $ 2,971 Lease Obligation 11 Total Liabilities $ 2,982 Cash Paid $ 29,306 The assignment of asset values is based on the final purchase price. In the fourth quarter of 2015, the Company elected to early adopt ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, Segment Information 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. 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 2015. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5% and 98.2% of its operating revenues for the respective three-month periods ended September 30, 2016 and 2015, and 98.6% and 97.2% of its operating revenues for the respective nine-month periods ended September 30, 2016 and 2015. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three- and nine-month periods ended September 30, 2016 and 2015 and total assets by business segment as of September 30, 2016 and December 31, 2015 are presented in the following tables: Operating Revenue Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 102,723 $ 100,567 $ 313,642 $ 305,078 Manufacturing 52,171 52,460 170,443 160,492 Plastics 42,292 47,025 122,841 125,531 Intersegment Eliminations (11 ) (29 ) (27 ) (84 ) Total $ 197,175 $ 200,023 $ 606,899 $ 591,017 Interest Charges Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 6,304 $ 6,069 $ 18,744 $ 18,273 Manufacturing 974 900 2,972 2,578 Plastics 273 257 796 782 Corporate and Intersegment Eliminations 475 504 1,484 1,542 Total $ 8,026 $ 7,730 $ 23,996 $ 23,175 Income Tax Expense—Continuing Operations Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 4,730 $ 4,761 $ 11,262 $ 9,995 Manufacturing 182 855 2,992 2,516 Plastics 1,577 2,206 5,206 6,159 Corporate (1,326 ) (1,301 ) (3,722 ) (4,068 ) Total $ 5,163 $ 6,521 $ 15,738 $ 14,602 Net Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 12,513 $ 12,921 $ 34,199 $ 34,351 Manufacturing 1,246 1,714 6,108 4,810 Plastics 2,346 3,534 7,983 9,919 Corporate (1,511 ) (2,460 ) (3,650 ) (5,933 ) Discontinued Operations 22 (317 ) 171 1,616 Total $ 14,616 $ 15,392 $ 44,811 $ 44,763 Identifiable Assets September 30, December 31, (in thousands) 2016 2015 Electric $ 1,575,790 $ 1,520,887 Manufacturing 168,705 173,860 Plastics 86,731 81,624 Corporate 37,432 42,312 Discontinued Operations 249 — Total $ 1,868,907 $ 1,818,683 |
Rate and Regulatory Matters
Rate and Regulatory Matters | 9 Months Ended |
Sep. 30, 2016 | |
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 2016 and 2015. Major Capital Expenditure Projects Big Stone Plant Air Quality Control System (AQCS) Fargo–Monticello 345 kiloVolt ( kV Capacity Expansion 2020 (CapX2020) Project (the Fargo Project) Brookings–Southeast Twin Cities 345 kV CapX2020 MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff ( 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 of MVPs is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. The Big Stone South–Brookings MVP and CapX2020 MVP MISO Tariff OTP’s capitalized cost of this project as of September 30, 2016 was approximately $56.4 million, which includes assets that are 100% owned by OTP. The Big Stone South–Ellendale MVP OTP’s capitalized cost of this project as of September 30, 2016 was approximately $39.8 million, which includes assets that are 100% owned by OTP. Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota 2016 General Rate Case Annualized or Actual Through September 30, 2016 ($ in thousands) Test Year Three Months Ended Nine Months Ended Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 3,818 $ 6,875 The major components of the requested rate increase are summarized below: Revenue Requirement Deficiency Cost Factors (in thousands) 2016 Test Year Increased Rate Base $ 10,000 Increased Expenses 7,700 Other 1,596 Total Requested Revenue Increase $ 19,296 Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset (2,480 ) Approved Interim Revenue Increase (subject to refund) $ 16,816 The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the MNDOC included a recommendation for an 8.86% 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. The deadline for submission of surrebuttal testimony was September 28, 2016. Hearings before the Administrative Law Judge (ALJ) occurred on October 13, 14 and 17, 2016. Based on OTP’s modifications to its original request and other expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $2.3 million as of September 30, 2016. Expected dates for next steps in the procedural schedule: · Report of ALJ ─ January 5, 2017 · Final order ─ March 16, 2017 2010 General Rate Case Minnesota Conservation Improvement Programs (MNCIP) The MNDOC has proposed changes to the MNCIP financial incentive mechanism. On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes to the MNCIP financial incentive. The new model will provide 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. The MNDOC opened an additional docket to investigate how investor-owned utilities calculate their avoided costs pertaining to generation capacity, energy, transmission and distribution. Avoided costs are the basis of MNCIP program benefits which going forward will establish OTP’s financial incentive. On May 23, 2016 the MNDOC accepted OTP’s 2017 avoided costs calculation, but is requiring Minnesota investor-owned utilities to undergo an analysis of transmission and distribution avoided costs for 2018 and 2019 with results to be submitted to the MNDOC by January 31, 2017. 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, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9, 2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016. OTP filed an update to its TCR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis, as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC granted an extension to the MNDOC to file initial comments in this docket until November 1, 2016. Environmental Cost Recovery Rider North Dakota General Rates Renewable Resource Adjustment the NDPSC approved OTP’s 2014 annual update to the NDRRA rider, including a change in rate design from an amount per kilowatt-hour consumed to a percentage of a customer’s bill, with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on December 31, 2015 with a requested implementation date of April 1, 2016. supplemental filing to address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016 . The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. Transmission Cost Recovery Rider Environmental Cost Recovery Rider On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. The ECR provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from 7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant Mercury and Air Toxics Standards (MATS) project costs. On March 31, 2016 OTP filed its annual update to the ECR rider requesting a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million, effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016. Reagent Costs and Emission Allowances South Dakota 2010 General Rate Case Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota: Three Months Ended Nine Months Ended Rate Rider (in thousands) 2016 2015 2016 2015 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,839 $ 1,970 $ 7,554 $ 5,508 Transmission Cost Recovery 779 1,141 4,188 3,968 Environmental Cost Recovery 3,127 2,565 9,362 7,722 North Dakota Renewable Resource Adjustment 2,170 2,073 6,151 5,898 Transmission Cost Recovery 1,950 1,565 6,155 4,912 Environmental Cost Recovery 2,762 2,312 8,344 7,233 South Dakota Transmission Cost Recovery 335 267 1,397 911 Environmental Cost Recovery 691 461 1,951 1,484 Conservation Improvement Program Costs and Incentives 135 234 418 464 1 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. Effective January 1, 2012 the FERC authorized OTP to recover 100% of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP. 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 are seeking to reduce the 12.38% ROE used in MISO’s transmission rates over a 15-month period ending in February 2015 to a proposed 9.15%. On October 16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing. 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. , 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% over a 15-month period ending in May 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings, 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%. The FERC is expected to issue its order in the spring of 2017. Based on a potential reduction by the FERC in the ROE component of the MISO Tariff, OTP recorded a reduction in revenue of $0.1 million in the three-month period ended September 30, 2015, and $1.3 million and $0.9 million in the nine-month periods ended September 30, 2016 and 2015, respectively, and has a $2.4 million liability on its balance sheet as of September 30, 2016, representing OTP’s best estimate of a refund obligation that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. As a result of the FERC order issued on September 28, 2016 in the first complaint proceeding establishing an allowed ROE of 10.32%, no additional liability was recorded in the third quarter of 2016. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 9 Months Ended |
Sep. 30, 2016 | |
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 September 30, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 94,671 $ 102,110 see below Deferred Marked-to-Market Losses 1 4,063 7,483 11,546 51 months Conservation Improvement Program Costs and Incentives 2 4,286 3,079 7,365 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,031 6,031 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 619 2,444 3,063 55 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,608 826 2,434 18 months Debt Reacquisition Premiums 1 349 1,278 1,627 192 months Deferred Income Taxes 1 — 1,157 1,157 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 748 — 748 12 months Big Stone II Unrecovered Project Costs – South Dakota 2 101 567 668 80 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 544 544 27 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 474 43 517 27 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 225 — 225 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 46 — 46 12 months Total Regulatory Assets $ 19,958 $ 118,123 $ 138,081 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 77,603 77,603 asset lives Refundable Fuel Clause Adjustment Revenues 2,301 — 2,301 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 638 758 1,396 24 months Minnesota Transmission Cost Recovery Rider Accrued Refund 1,356 — 1,356 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 712 385 1,097 19 months Deferred Income Taxes — 918 918 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 370 — 370 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 296 — 296 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 256 — 256 12 months Other 5 91 96 207 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 80 80 27 months Total Regulatory Liabilities $ 5,934 $ 79,835 $ 85,769 Net Regulatory Asset Position $ 14,024 $ 38,288 $ 52,312 1 2 December 31, 2015 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 99,293 $ 106,732 see below Deferred Marked-to-Market Losses 1 4,063 10,530 14,593 60 months Conservation Improvement Program Costs and Incentives 2 4,411 4,266 8,677 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,672 5,672 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 942 2,620 3,562 84 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Deferred Income Taxes 1 — 1,455 1,455 asset lives North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Total Regulatory Assets $ 18,904 $ 127,707 $ 146,611 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 74,948 $ 74,948 asset lives Refundable Fuel Clause Adjustment Revenues 1,834 — 1,834 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota — 1,279 1,279 see below Deferred Income Taxes — 1,110 1,110 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Renewable Resource Rider Accrued Refund 68 — 68 12 months Total Regulatory Liabilities $ 3,322 $ 77,432 $ 80,754 Net Regulatory Asset Position $ 15,582 $ 50,275 $ 65,857 1 2 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 All Deferred Marked-to-Market Losses recorded as of September 30, 2016 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. North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of September 30, 2016. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 192 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. 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 September 30, 2016. 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 September 30, 2016. 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 September 30, 2016. The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of September 30, 2016. 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 September 30, 2016. The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of September 30, 2016. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of September 30, 2016. 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. |
Open Contract Positions Subject
Open Contract Positions Subject to Legally Enforceable Netting Arrangements | 9 Months Ended |
Sep. 30, 2016 | |
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 forward contract fair value positions subject to legally enforceable netting arrangements as of September 30, 2016 and December 31, 2015: (in thousands) September 30, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (15,220 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (15,220 ) $ (16,070 ) The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in loss positions as of September 30, 2016 and December 31, 2015: Loss Position (in thousands) September 30, December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 49 $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 15,171 15,871 Loss Contracts with No Ratings Triggers or Deposit Requirements — — Loss Position $ 15,220 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 15,171 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,171 $ 15,871 |
Reconciliation of Common Shareh
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 9 Months Ended |
Sep. 30, 2016 | |
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, Premium Retained Accumulated Total Balance, December 31, 2015 $ 189,286 $ 293,610 $ 126,025 $ (3,898 ) $ 605,023 Common Stock Issuances, Net of Expenses 6,855 34,601 41,456 Common Stock Retirements (18 ) (86 ) (104 ) Net Income 44,811 44,811 Other Comprehensive Income 322 322 Employee Stock Incentive Plans Expense 1,163 1,163 Common Dividends ($0.9375 per share) (35,952 ) (35,952 ) Balance, September 30, 2016 $ 196,123 $ 329,288 $ 134,884 $ (3,576 ) $ 656,719 Shelf Registration 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, 2015 through September 30, 2016: Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 977,712 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 131,111 Cash Invested 79,494 Executive Stock Performance Awards (2013 and 2014 shares earned) 54,700 Employee Stock Purchase Plan: Cash Invested 40,324 Dividends Reinvested 19,090 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,025 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, September 30, 2016 39,224,553 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three- and nine-month periods ended September 30, 2016 and 2015. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation: Three Months ended Nine Months ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 38,832,659 37,575,413 38,316,324 37,417,283 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 103,084 141,540 80,450 141,540 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 48,645 44,280 42,620 44,280 Nonvested Restricted Shares 18,029 31,079 14,556 31,079 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,289 2,231 3,451 2,231 Total Dilutive Shares 173,047 219,130 141,077 219,130 Weighted Average Common Shares Outstanding – Diluted 39,005,706 37,794,543 38,457,401 37,636,413 The effect of dilutive shares on earnings per share for the three- and nine-month periods ended September 30, 2016 and 2015, 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. |
Share-Based Payments
Share-Based Payments | 9 Months Ended |
Sep. 30, 2016 | |
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | |
Share-Based Payments | 7. Share-Based Payments Stock Incentive Awards In 2016 the following stock incentive awards were granted to the Company’s employees and nonemployee directors under the 2014 Stock Incentive Plan: Award Shares/ Grant-Date Vesting February 4, 2016: Stock Performance Awards Granted to Executive Officers 81,500 $ 24.03 December 31, 2018 Restricted Stock Units Granted to Executive Officers 22,000 $ 28.915 25% per year through February 6, 2020 April 11, 2016: Restricted Stock Granted to Nonemployee Directors 23,200 $ 28.66 25% per year through April 8, 2020 Restricted Stock Units Granted to Key Employees 15,800 $ 24.00 100% on April 8, 2020 September 21, 2016: Restricted Stock Units Granted to Key Employee 1,420 $ 30.59 100% on April 8, 2020 Under the 2016 performance share award agreements, the aggregate award for performance at target is 81,500 shares. For target performance the Company’s executive officers would earn an aggregate of 54,333 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, 2016 through December 31, 2018, 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, 2016 and the average closing price for the 20 trading days immediately preceding January 1, 2019, respectively. The Company’s executive officers would also earn an aggregate of 27,167 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. Actual payment may range from zero to 150% of the target amount, or up to an aggregate of 122,250 common shares. The executive officers have no voting or dividend rights related to these shares until the 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 a liability, as required under ASC Topic 718, Compensation—Stock Compensation Under the 2016 performance share 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 the target amount at the date of any such event. The vesting of these performance share award agreements is accelerated and paid out at target in the event of a change in control, disability or death (and on retirement at or after the age of 62 for certain officers who are parties to executive employment agreements with the Company). Vesting of restricted stock and restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price per share on the date of grant. The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was based on the market value of one share of the Company’s common stock on the date of grant. The grant-date fair value of each restricted stock unit granted to a key employee that is not an executive officer of the Company was based on the market value of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the four-year vesting period. The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of September 30, 2016 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.1 million (before income taxes) which will be amortized over a weighted-average period of 2.4 years. Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three- and nine-month periods ended September 30, 2016 and 2015 are presented in the table below: Three Months Ended Nine Months Ended (in thousands) 2016 2015 2016 2015 Stock Performance Awards Granted to Executive Officers $ 455 $ (142 ) $ 1,296 $ 915 Restricted Stock Units Granted to Executive Officers 64 36 373 416 Restricted Stock Granted to Executive Officers 22 29 73 330 Restricted Stock Granted to Directors 128 107 363 311 Restricted Stock Units Granted to Nonexecutive Employees 62 86 207 233 Employee Stock Purchase Plan (15% discount) 47 44 135 138 Totals $ 778 $ 160 $ 2,447 $ 2,343 |
Retained Earnings Restriction
Retained Earnings Restriction | 9 Months Ended |
Sep. 30, 2016 | |
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, there are limitations 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 on a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2016 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, 2015 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, 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. OTP’s equity to total capitalization ratio including short-term debt was 52.9% as of September 30, 2016. Total capitalization for OTP cannot currently exceed $1,123,168,000. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 9. Commitments and Contingencies Construction and Other Purchase Commitments At December 31, 2015 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $89.6 million. At September 30, 2016 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $137.4 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. In 2016, OTP entered into a $3.5 million electric generating capacity purchase agreement for the period June 2017 through May 2019. OTP has commitments under contracts providing for the purchase and delivery of a significant portion of its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040, respectively. In January 2016, OTP entered into 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. On September 27, 2016 OTP entered into an agreement to lease rail cars for the delivery of coal to Big Stone Plant through October of 2026 with OTP’s share of the lease payments totaling $970,000 over the term of the lease. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. Contingencies Based on the reduction by the FERC in the ROE component of the MISO Tariff, OTP has a $2.4 million liability on its balance sheet as of September 30, 2016, representing OTP’s best estimate of its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery under state jurisdictional TCR riders. OTP was a party to 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. As many as 200 utilities, generators and power marketers participated in the proceedings, which concluded on May 2, 2016. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with FERC to market participants, revisions to the RSG rate based on several FERC orders and 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 United States Court of Appeals for the District of Columbia (D.C. Circuit). The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is both a petitioner and an intervenor in these cases. 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 CO2 emissions from new fossil fuel-fired power plants, proposed CO2 emission guidelines for existing fossil fuel-fired power plants and proposed CO2 standards of performance for CO2 emissions from reconstructed and modified fossil fuel-fired power plants 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 CO2 emission guidelines for existing fossil fuel-fired power plants, 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 CO2 emission guidelines on September 27, 2016 before the full court, and a decision may be rendered in late 2016 or early 2017. Given the pending litigation, uncertainty regarding the status of the rules will likely continue for some time. OTP is actively engaged with the stakeholder processes in each of its states that have continued to move forward with planning efforts during the stay. 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 other matters pending as of September 30, 2016 will not be material. |
Short-Term and Long-Term Borrow
Short-Term and Long-Term Borrowings | 9 Months Ended |
Sep. 30, 2016 | |
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 September 30, 2016 and December 31, 2015: (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ — $ — $ 150 000 $ 90,334 OTP Credit Agreement 170,000 37,173 50 132,777 148,694 Total $ 320,000 $ 37,173 $ 50 $ 282,777 $ 239,028 On October 31, 2016 both the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were amended to extend the expiration dates by one year from October 29, 2020 to October 29, 2021. Also, the line limit on the Otter Tail Corporation Credit Agreement was reduced from $150 million to $130 million. Debt Issuances and Retirements 2016 Note Purchase Agreement The Company 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 the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is 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 the Company and its Material Subsidiaries sell a “substantial part” of 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, the Company is 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 the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement. These include restrictions on the Company’s and the 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 the Company’s and the 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. Specifically, the Company may not permit the ratio of its Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) to Total Capitalization (as defined in the 2016 Note Purchase Agreement) to be greater than 0.60 to 1.00, determined as of the end of each fiscal quarter, and may not permit the Interest and Dividend Coverage Ratio (as defined in the 2016 Note Purchase Agreement) to be less than 1.50 to 1.00 for any period of four consecutive fiscal quarters. The Company is also restricted from allowing its Priority Debt (as defined in the 2016 Note Purchase Agreement) to exceed 10% of Total Capitalization, determined as of the end of each fiscal quarter. 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 the Company’s or the Material Subsidiaries’ credit ratings. The Company intends to use the proceeds of the 2026 Notes to repay existing debt, including the remaining $52,330,000 of its 9.000% Senior Notes due December 15, 2016, and for general corporate purposes. $50 Million Term Loan Agreement On February 5, 2016 the Company 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. The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2016 and December 31, 2015: September 30, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 37,173 $ — $ 37,173 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 Term Loan, LIBOR plus 0.90%, due February 5, 2018 50,000 50,000 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 126 126 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 873 873 Total $ 445,000 $ 103,329 $ 548,329 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,958 52,532 85,490 Unamortized Long-Term Debt Issuance Costs 1,920 162 2,082 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,122 $ 50,635 $ 460,757 Total Short-Term and Long-Term Debt (with current maturities) $ 480,253 $ 103,167 $ 583,420 December 31, 2015 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 21,006 $ 59,666 $ 80,672 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 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 182 182 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 977 977 Total $ 445,000 $ 53,489 $ 498,489 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,422 52,422 Unamortized Long-Term Debt Issuance Costs 2,099 122 2,221 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 442,901 $ 945 $ 443,846 Total Short-Term and Long-Term Debt (with current maturities) $ 463,907 $ 113,033 $ 576,940 |
Pension Plan and Other Postreti
Pension Plan and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Pension Plan and Other Postretirement Benefits | 11. Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 1,376 $ 1,514 $ 4,139 $ 4,544 Interest Cost on Projected Benefit Obligation 3,603 3,336 10,646 10,008 Expected Return on Assets (4,857 ) (4,595 ) (14,590 ) (13,787 ) Amortization of Prior-Service Cost: From Regulatory Asset 48 47 142 141 From Other Comprehensive Income 1 1 2 3 4 Amortization of Net Actuarial Loss: From Regulatory Asset 1,411 1,669 3,865 5,007 From Other Comprehensive Income 1 32 42 95 128 Net Periodic Pension Cost $ 1,614 $ 2,015 $ 4,300 $ 6,045 1 Cash flows Executive Survivor and Supplemental Retirement Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 63 $ 48 $ 189 $ 142 Interest Cost on Projected Benefit Obligation 417 380 1,251 1,142 Amortization of Prior-Service Cost: From Regulatory Asset 4 5 12 13 From Other Comprehensive Income 1 9 9 28 28 Amortization of Net Actuarial Loss: From Regulatory Asset 74 83 220 250 From Other Comprehensive Income 2 111 151 334 452 Net Periodic Pension Cost $ 678 $ 676 $ 2,034 $ 2,027 1 Electric Operation and Maintenance Expenses $ 3 $ 3 $ 11 $ 11 Other Nonelectric Expenses 6 6 17 17 2 Electric Operation and Maintenance Expenses $ 68 $ 78 $ 204 $ 233 Other Nonelectric Expenses 43 73 130 219 Postretirement Benefits Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 365 $ 324 $ 976 $ 972 Interest Cost on Projected Benefit Obligation 794 524 1,877 1,573 Amortization of Prior-Service Cost: From Regulatory Asset 34 52 100 154 From Other Comprehensive Income 1 1 1 3 4 Amortization of Net Actuarial Loss: From Regulatory Asset 284 — 284 — From Other Comprehensive Income 1 7 — 7 — Net Periodic Postretirement Benefit Cost $ 1,485 $ 901 $ 3,247 $ 2,703 Effect of Medicare Part D Subsidy $ (177 ) $ (372 ) $ (692 ) $ (1,115 ) 1 Corporate cost included in Other Nonelectric Expenses. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2016 | |
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 Long-Term Debt including Current Maturities September 30, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (37,173 ) (37,173 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (546,247 ) (618,875 ) (496,268 ) (561,245 ) |
Income Tax Expense Continuing
Income Tax Expense Continuing Operations | 9 Months Ended |
Sep. 30, 2016 | |
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: Three Months Ended Nine Months Ended (in thousands) 2016 2015 2016 2015 Income Before Income Taxes – Continuing Operations $ 19,757 $ 22,230 $ 60,378 $ 57,749 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 7,705 8,670 23,547 22,522 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,423 ) (1,437 ) (4,994 ) (5,147 ) R&D Tax Credits (223 ) 2 (445 ) (7 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (212 ) (212 ) (637 ) (637 ) Employee Stock Ownership Plan Dividend Deduction (157 ) (171 ) (472 ) (514 ) Corporate Owned Life Insurance (92 ) 185 (664 ) (39 ) Investment Tax Credits (87 ) (143 ) (262 ) (428 ) Adjustment for Uncertain Tax Positions (57 ) 281 (31 ) 367 AFUDC Equity (51 ) (144 ) (238 ) (369 ) Section 199 Domestic Production Activities Deduction (9 ) (362 ) (207 ) (1,087 ) Other Items – Net (231 ) (148 ) 141 (59 ) Income Tax Expense – Continuing Operations $ 5,163 $ 6,521 $ 15,738 $ 14,602 Effective Income Tax Rate – Continuing Operations 26.1 % 29.3 % 26.1 % 25.3 % The following table summarizes the activity related to our unrecognized tax benefits: (in thousands) 2016 2015 Balance on January 1 $ 468 $ 222 Increases Related to Tax Positions for Prior Years 40 236 Increases Related to Tax Positions for Current Year 26 131 Uncertain Positions Resolved During Year (97 ) — Balance on September 30 $ 437 $ 589 The balance of unrecognized tax benefits as of September 30, 2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2016 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of September 30, 2016. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2016, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal income taxes and Minnesota and North Dakota state income taxes. |
Discontinued Operations
Discontinued Operations | 9 Months Ended |
Sep. 30, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | 16. Discontinued Operations On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor. On February 28, 2015 the Company sold the assets of AEV, Inc. its . For the Three Months Ended For the Nine Months Ended (in thousands) 2016 2015 2016 2015 Operating Revenues $ — $ — $ — $ 24,623 Operating Expenses (36 ) 420 (285 ) 31,770 Goodwill Impairment Charge — — — 1,000 Operating Income (Loss) 36 (420 ) 285 (8,147 ) Other Deductions — — — (42 ) Income Tax Expense (Benefit) 14 (168 ) 114 (2,873 ) Net Income (Loss) from Operations 22 (252 ) 171 (5,316 ) (Loss) Gain on Disposition Before Taxes — (108 ) — 11,425 Income Tax (Benefit) Expense on Disposition — (43 ) — 4,493 Net (Loss) Gain on Disposition — (65 ) — 6,932 Net Income (Loss) $ 22 $ (317 ) $ 171 $ 1,616 The above results for the nine months ended September 30, 2015 include net losses from operations of $4.1 million from Foley, $0.8 million from AEV, Inc. and $0.6 million, mainly related to the settlement of a warranty claim in the second quarter of 2015, from the Company’s former waterfront equipment manufacturer, and net income of $0.2 million from the Company’s former wind tower manufacturer related to a reduction in warranty reserves for expired warranties. Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges $4.4 million in the nine-month period ended September 30, 2015. Following are summary presentations of the major components of assets and liabilities of discontinued operations as of September 30, 2016 and December 31, 2015: (in thousands) September, 30 December 31, Current Assets $ 249 $ — Assets of Discontinued Operations $ 249 $ — Current Liabilities $ 1,631 $ 2,098 Liabilities of Discontinued Operations $ 1,631 $ 2,098 Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow: (in thousands) 2016 2015 Warranty Reserve Balance, January 1 $ 2,103 $ 2,527 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year (24 ) (115 ) Decrease in Warranty Estimates for Prior Years (530 ) (100 ) Warranty Reserve Balance, September 30 $ 1,549 $ 2,312 The warranty reserve balances as of September 30, 2016 relate entirely 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. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
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. In the case of derivative instruments, such as Otter Tail Power Company’s (OTP) 2015 forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging 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 ASC Topic 820, Fair Value Measurements and Disclosures Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX). Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015: September 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,408 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 3,506 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 764 Total Assets $ 764 $ 7,914 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 49 Total Liabilities $ 49 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Forward Gasoline Purchase Contracts Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company |
Inventories | Inventories Inventories consist of the following: September 30, December 31, (in thousands) 2016 2015 Finished Goods $ 21,888 $ 25,971 Work in Process 13,774 12,821 Raw Material, Fuel and Supplies 45,186 46,624 Total Inventories $ 80,848 $ 85,416 |
Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois), a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville, Georgia. The newly acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2 million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information. An assessment of the carrying amounts of the remaining goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2015 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table summarizes changes to goodwill by business segment during 2016: (in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2016 and December 31, 2015: September 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,577 $ 14,914 39-227 months Covenant not to Compete 590 213 377 23 months Total $ 23,081 $ 7,790 $ 15,291 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 348 $ 282 $ 1,103 $ 770 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099 |
Supplemental Disclosures of Cash Flow Information | Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,552 $ 21,760 |
Coyote Station Lignite Supply Agreement - Variable Interest Entity | Coyote Station Lignite Supply Agreement – Variable Interest Entity Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commenced with the initial delivery of coal to Coyote Station in May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. 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. Coyote Station started taking delivery of coal and paying for coal and the accumulated development fees and capital charges under the LSA in May 2016. OTP’s 35% share of the unrecovered development period costs, development fees and capital charges incurred by CCMC through September 30, 2016 is $61.7 million. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of September 30, 2016 could be as high as $61.7 million. |
New Accounting Standards | New Accounting Standards ASU 2014-09 Revenue from Contracts with Customers (Topic 606) 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 September 30, 2016 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. The Company does not plan to adopt the updated guidance prior to January 1, 2018. ASU 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683 ASU 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, ASU 2016-02 Leases (Topic 842) ASU 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Schedule of assets and liabilities that are measured at fair value on a recurring basis | September 30, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 4,408 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 3,506 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 764 Total Assets $ 764 $ 7,914 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 49 Total Liabilities $ 49 December 31, 2015 (in thousands) Level 1 Level 2 Level 3 Assets: Current Assets – Other: Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions $ 2,000 Investments: Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company $ 4,235 Corporate Debt Securities – Held by Captive Insurance Company 3,858 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 196 Total Assets $ 2,196 $ 8,093 Liabilities: Other Accrued Liabilities: Derivative Liabilities – Forward Gasoline Purchase Contracts $ 199 Total Liabilities $ 199 |
Schedule of inventories | September 30, December 31, (in thousands) 2016 2015 Finished Goods $ 21,888 $ 25,971 Work in Process 13,774 12,821 Raw Material, Fuel and Supplies 45,186 46,624 Total Inventories $ 80,848 $ 85,416 |
Schedule of changes to goodwill by business segment | (in thousands) Gross Balance Accumulated Balance (net of Adjustments Balance (net of Manufacturing $ 20,430 $ — $ 20,430 $ (2,160 ) $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 39,732 $ — $ 39,732 $ (2,160 ) $ 37,572 |
Schedule of components of intangible assets | September 30, 2016 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,577 $ 14,914 39-227 months Covenant not to Compete 590 213 377 23 months Total $ 23,081 $ 7,790 $ 15,291 December 31, 2015 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 21,681 $ 6,714 $ 14,967 48-236 months Covenant not to Compete 620 69 551 32 months Other Intangible Assets 639 543 96 9 months Emission Allowances 59 NA 59 Expensed as used Total $ 22,999 $ 7,326 $ 15,673 |
Schedule of amortization expense for intangible assets | Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Amortization Expense – Intangible Assets $ 348 $ 282 $ 1,103 $ 770 |
Schedule of estimated annual amortization expense for intangible assets | (in thousands) 2016 2017 2018 2019 2020 Estimated Amortization Expense – Intangible Assets $ 1,436 $ 1,330 $ 1,264 $ 1,133 $ 1,099 |
Schedule of supplemental disclosure of cash flow information | As of September 30, (in thousands) 2016 2015 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,552 $ 21,760 |
Schedule of effects of applying the guidance and reclassification of unamortized line of credit issuance costs | (in thousands) Previously Adjustments Restated Other Assets $ 31,108 $ 1,676 $ 32,784 Unamortized Debt Expense 3,897 (3,897 ) — Total Assets 1,820,904 (2,221 ) 1,818,683 Current Liabilities Current Maturities of Long-Term Debt 52,544 (122 ) 52,422 Total Current Liabilities 271,238 (122 ) 271,116 Capitalization Long-Term Debt—Net 445,945 (2,099 ) 443,846 Total Capitalization 1,050,968 (2,099 ) 1,048,869 Total Liabilities and Equity 1,820,904 (2,221 ) 1,818,683 |
Business Combinations and Seg24
Business Combinations and Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Acquisition And Segment Information [Abstract] | |
Schedule of business combination disclosing the final allocation of purchase price to each major asset and liability | (in thousands) Assets: Current Assets $ 4,906 Goodwill 6,083 Other Intangible Assets 6,270 Other Amortizable Assets 1,380 Fixed Assets 13,649 Total Assets $ 32,288 Liabilities: Current Liabilities $ 2,971 Lease Obligation 11 Total Liabilities $ 2,982 Cash Paid $ 29,306 |
Schedule of information by business segments | Operating Revenue Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 102,723 $ 100,567 $ 313,642 $ 305,078 Manufacturing 52,171 52,460 170,443 160,492 Plastics 42,292 47,025 122,841 125,531 Intersegment Eliminations (11 ) (29 ) (27 ) (84 ) Total $ 197,175 $ 200,023 $ 606,899 $ 591,017 Interest Charges Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 6,304 $ 6,069 $ 18,744 $ 18,273 Manufacturing 974 900 2,972 2,578 Plastics 273 257 796 782 Corporate and Intersegment Eliminations 475 504 1,484 1,542 Total $ 8,026 $ 7,730 $ 23,996 $ 23,175 Income Tax Expense—Continuing Operations Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 4,730 $ 4,761 $ 11,262 $ 9,995 Manufacturing 182 855 2,992 2,516 Plastics 1,577 2,206 5,206 6,159 Corporate (1,326 ) (1,301 ) (3,722 ) (4,068 ) Total $ 5,163 $ 6,521 $ 15,738 $ 14,602 Net Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2016 2015 2016 2015 Electric $ 12,513 $ 12,921 $ 34,199 $ 34,351 Manufacturing 1,246 1,714 6,108 4,810 Plastics 2,346 3,534 7,983 9,919 Corporate (1,511 ) (2,460 ) (3,650 ) (5,933 ) Discontinued Operations 22 (317 ) 171 1,616 Total $ 14,616 $ 15,392 $ 44,811 $ 44,763 Identifiable Assets September 30, December 31, (in thousands) 2016 2015 Electric $ 1,575,790 $ 1,520,887 Manufacturing 168,705 173,860 Plastics 86,731 81,624 Corporate 37,432 42,312 Discontinued Operations 249 — Total $ 1,868,907 $ 1,818,683 |
Rate and Regulatory Matters (Ta
Rate and Regulatory Matters (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Rate and Regulatory Matters [Abstract] | |
Schedule of request and interim rate information | The request and interim rate information is detailed in the table below: Annualized or Actual Through September 30, 2016 ($ in thousands) Test Year Three Months Ended Nine Months Ended Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 3,818 $ 6,875 The major components of the requested rate increase are summarized below: Revenue Requirement Deficiency Cost Factors (in thousands) 2016 Test Year Increased Rate Base $ 10,000 Increased Expenses 7,700 Other 1,596 Total Requested Revenue Increase $ 19,296 Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset (2,480 ) Approved Interim Revenue Increase (subject to refund) $ 16,816 |
Schedule of revenues recorded under rate riders | Three Months Ended Nine Months Ended Rate Rider (in thousands) 2016 2015 2016 2015 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,839 $ 1,970 $ 7,554 $ 5,508 Transmission Cost Recovery 779 1,141 4,188 3,968 Environmental Cost Recovery 3,127 2,565 9,362 7,722 North Dakota Renewable Resource Adjustment 2,170 2,073 6,151 5,898 Transmission Cost Recovery 1,950 1,565 6,155 4,912 Environmental Cost Recovery 2,762 2,312 8,344 7,233 South Dakota Transmission Cost Recovery 335 267 1,397 911 Environmental Cost Recovery 691 461 1,951 1,484 Conservation Improvement Program Costs and Incentives 135 234 418 464 1 |
Regulatory Assets and Liabili26
Regulatory Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of amount of regulatory assets and liabilities | September 30, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 94,671 $ 102,110 see below Deferred Marked-to-Market Losses 1 4,063 7,483 11,546 51 months Conservation Improvement Program Costs and Incentives 2 4,286 3,079 7,365 24 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,031 6,031 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 619 2,444 3,063 55 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,608 826 2,434 18 months Debt Reacquisition Premiums 1 349 1,278 1,627 192 months Deferred Income Taxes 1 — 1,157 1,157 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 748 — 748 12 months Big Stone II Unrecovered Project Costs – South Dakota 2 101 567 668 80 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 544 544 27 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 474 43 517 27 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 225 — 225 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 46 — 46 12 months Total Regulatory Assets $ 19,958 $ 118,123 $ 138,081 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 77,603 77,603 asset lives Refundable Fuel Clause Adjustment Revenues 2,301 — 2,301 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 638 758 1,396 24 months Minnesota Transmission Cost Recovery Rider Accrued Refund 1,356 — 1,356 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota 712 385 1,097 19 months Deferred Income Taxes — 918 918 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 370 — 370 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 296 — 296 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 256 — 256 12 months Other 5 91 96 207 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 80 80 27 months Total Regulatory Liabilities $ 5,934 $ 79,835 $ 85,769 Net Regulatory Asset Position $ 14,024 $ 38,288 $ 52,312 1 2 December 31, 2015 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 7,439 $ 99,293 $ 106,732 see below Deferred Marked-to-Market Losses 1 4,063 10,530 14,593 60 months Conservation Improvement Program Costs and Incentives 2 4,411 4,266 8,677 18 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 5,672 5,672 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 942 2,620 3,562 84 months Debt Reacquisition Premiums 1 351 1,539 1,890 201 months Deferred Income Taxes 1 — 1,455 1,455 asset lives North Dakota Renewable Resource Rider Accrued Revenues 2 — 1,266 1,266 15 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 698 355 1,053 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 643 743 89 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 576 — 576 12 months Minnesota Deferred Rate Case Expenses Subject to Recovery 1 291 — 291 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 — 68 68 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 33 — 33 12 months Total Regulatory Assets $ 18,904 $ 127,707 $ 146,611 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 74,948 $ 74,948 asset lives Refundable Fuel Clause Adjustment Revenues 1,834 — 1,834 12 months Revenue for Rate Case Expenses Subject to Refund – Minnesota — 1,279 1,279 see below Deferred Income Taxes — 1,110 1,110 asset lives Minnesota Environmental Cost Recovery Rider Accrued Refund 777 — 777 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 321 — 321 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 185 — 185 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 132 — 132 12 months Deferred Gain on Sale of Utility Property – Minnesota Portion 5 95 100 216 months North Dakota Renewable Resource Rider Accrued Refund 68 — 68 12 months Total Regulatory Liabilities $ 3,322 $ 77,432 $ 80,754 Net Regulatory Asset Position $ 15,582 $ 50,275 $ 65,857 1 2 |
Open Contract Positions Subje27
Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
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) September 30, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (15,220 ) (16,070 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (15,220 ) $ (16,070 ) |
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions | Loss Position (in thousands) September 30, December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ 49 $ 199 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 15,171 15,871 Loss Contracts with No Ratings Triggers or Deposit Requirements — — Loss Position $ 15,220 $ 16,070 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 15,171 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,171 $ 15,871 |
Reconciliation of Common Shar28
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Stockholders Equity and Earnings Per Share [Abstract] | |
Schedule of reconciliation of common shareholders' equity | (in thousands) Par Value, Premium Retained Accumulated Total Balance, December 31, 2015 $ 189,286 $ 293,610 $ 126,025 $ (3,898 ) $ 605,023 Common Stock Issuances, Net of Expenses 6,855 34,601 41,456 Common Stock Retirements (18 ) (86 ) (104 ) Net Income 44,811 44,811 Other Comprehensive Income 322 322 Employee Stock Incentive Plans Expense 1,163 1,163 Common Dividends ($0.9375 per share) (35,952 ) (35,952 ) Balance, September 30, 2016 $ 196,123 $ 329,288 $ 134,884 $ (3,576 ) $ 656,719 |
Schedule of common shares outstanding from December 31, 2015 through March 31, 2016 | Common Shares Outstanding, December 31, 2015 37,857,186 Issuances: At-the-Market Offering 977,712 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 131,111 Cash Invested 79,494 Executive Stock Performance Awards (2013 and 2014 shares earned) 54,700 Employee Stock Purchase Plan: Cash Invested 40,324 Dividends Reinvested 19,090 Employee Stock Ownership Plan 23,837 Restricted Stock Issued to Directors 23,200 Vesting of Restricted Stock Units 21,025 Directors Deferred Compensation 542 Retirements: Shares Withheld for Individual Income Tax Requirements (3,668 ) Common Shares Outstanding, September 30, 2016 39,224,553 |
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted | Three Months ended Nine Months ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 38,832,659 37,575,413 38,316,324 37,417,283 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 103,084 141,540 80,450 141,540 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 48,645 44,280 42,620 44,280 Nonvested Restricted Shares 18,029 31,079 14,556 31,079 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,289 2,231 3,451 2,231 Total Dilutive Shares 173,047 219,130 141,077 219,130 Weighted Average Common Shares Outstanding – Diluted 39,005,706 37,794,543 38,457,401 37,636,413 |
Share-Based Payments (Tables)
Share-Based Payments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | |
Schedule of stock incentive awards granted | Award Shares/ Grant-Date Vesting February 4, 2016: Stock Performance Awards Granted to Executive Officers 81,500 $ 24.03 December 31, 2018 Restricted Stock Units Granted to Executive Officers 22,000 $ 28.915 25% per year through February 6, 2020 April 11, 2016: Restricted Stock Granted to Nonemployee Directors 23,200 $ 28.66 25% per year through April 8, 2020 Restricted Stock Units Granted to Key Employees 15,800 $ 24.00 100% on April 8, 2020 September 21, 2016: Restricted Stock Units Granted to Key Employee 1,420 $ 30.59 100% on April 8, 2020 |
Schedule of compensation expense under stock-based payment programs | Three Months Ended Nine Months Ended (in thousands) 2016 2015 2016 2015 Stock Performance Awards Granted to Executive Officers $ 455 $ (142 ) $ 1,296 $ 915 Restricted Stock Units Granted to Executive Officers 64 36 373 416 Restricted Stock Granted to Executive Officers 22 29 73 330 Restricted Stock Granted to Directors 128 107 363 311 Restricted Stock Units Granted to Nonexecutive Employees 62 86 207 233 Employee Stock Purchase Plan (15% discount) 47 44 135 138 Totals $ 778 $ 160 $ 2,447 $ 2,343 |
Short-Term and Long-Term Borr30
Short-Term and Long-Term Borrowings (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of lines of credit | (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 150,000 $ — $ — $ 150 000 $ 90,334 OTP Credit Agreement 170,000 37,173 50 132,777 148,694 Total $ 320,000 $ 37,173 $ 50 $ 282,777 $ 239,028 |
Schedule of short-term and long-term debt outstanding | September 30, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 37,173 $ — $ 37,173 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 Term Loan, LIBOR plus 0.90%, due February 5, 2018 50,000 50,000 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 126 126 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 873 873 Total $ 445,000 $ 103,329 $ 548,329 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,958 52,532 85,490 Unamortized Long-Term Debt Issuance Costs 1,920 162 2,082 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,122 $ 50,635 $ 460,757 Total Short-Term and Long-Term Debt (with current maturities) $ 480,253 $ 103,167 $ 583,420 December 31, 2015 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 21,006 $ 59,666 $ 80,672 Long-Term Debt: 9.000% Notes, due December 15, 2016 $ 52,330 $ 52,330 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 182 182 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 977 977 Total $ 445,000 $ 53,489 $ 498,489 Less: Current Maturities net of Unamortized Debt Issuance Costs 52,422 52,422 Unamortized Long-Term Debt Issuance Costs 2,099 122 2,221 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 442,901 $ 945 $ 443,846 Total Short-Term and Long-Term Debt (with current maturities) $ 463,907 $ 113,033 $ 576,940 |
Pension Plan and Other Postre31
Pension Plan and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Pension Plan | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 1,376 $ 1,514 $ 4,139 $ 4,544 Interest Cost on Projected Benefit Obligation 3,603 3,336 10,646 10,008 Expected Return on Assets (4,857 ) (4,595 ) (14,590 ) (13,787 ) Amortization of Prior-Service Cost: From Regulatory Asset 48 47 142 141 From Other Comprehensive Income 1 1 2 3 4 Amortization of Net Actuarial Loss: From Regulatory Asset 1,411 1,669 3,865 5,007 From Other Comprehensive Income 1 32 42 95 128 Net Periodic Pension Cost $ 1,614 $ 2,015 $ 4,300 $ 6,045 1 |
Executive Survivor and Supplemental Retirement Plan | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 63 $ 48 $ 189 $ 142 Interest Cost on Projected Benefit Obligation 417 380 1,251 1,142 Amortization of Prior-Service Cost: From Regulatory Asset 4 5 12 13 From Other Comprehensive Income 1 9 9 28 28 Amortization of Net Actuarial Loss: From Regulatory Asset 74 83 220 250 From Other Comprehensive Income 2 111 151 334 452 Net Periodic Pension Cost $ 678 $ 676 $ 2,034 $ 2,027 1 Electric Operation and Maintenance Expenses $ 3 $ 3 $ 11 $ 11 Other Nonelectric Expenses 6 6 17 17 2 Electric Operation and Maintenance Expenses $ 68 $ 78 $ 204 $ 233 Other Nonelectric Expenses 43 73 130 219 |
Postretirement Benefits | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2016 2015 2016 2015 Service Cost—Benefit Earned During the Period $ 365 $ 324 $ 976 $ 972 Interest Cost on Projected Benefit Obligation 794 524 1,877 1,573 Amortization of Prior-Service Cost: From Regulatory Asset 34 52 100 154 From Other Comprehensive Income 1 1 1 3 4 Amortization of Net Actuarial Loss: From Regulatory Asset 284 — 284 — From Other Comprehensive Income 1 7 — 7 — Net Periodic Postretirement Benefit Cost $ 1,485 $ 901 $ 3,247 $ 2,703 Effect of Medicare Part D Subsidy $ (177 ) $ (372 ) $ (692 ) $ (1,115 ) 1 Corporate cost included in Other Nonelectric Expenses. |
Fair Value of Financial Instr32
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of long-term debt including current maturities | September 30, 2016 December 31, 2015 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (37,173 ) (37,173 ) (80,672 ) (80,672 ) Long-Term Debt including Current Maturities (546,247 ) (618,875 ) (496,268 ) (561,245 ) |
Income Tax Expense - Continuing
Income Tax Expense - Continuing Operations (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of income from continuing operations before income taxes and income tax expense | Three Months Ended Nine Months Ended (in thousands) 2016 2015 2016 2015 Income Before Income Taxes – Continuing Operations $ 19,757 $ 22,230 $ 60,378 $ 57,749 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 7,705 8,670 23,547 22,522 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,423 ) (1,437 ) (4,994 ) (5,147 ) R&D Tax Credits (223 ) 2 (445 ) (7 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (212 ) (212 ) (637 ) (637 ) Employee Stock Ownership Plan Dividend Deduction (157 ) (171 ) (472 ) (514 ) Corporate Owned Life Insurance (92 ) 185 (664 ) (39 ) Investment Tax Credits (87 ) (143 ) (262 ) (428 ) Adjustment for Uncertain Tax Positions (57 ) 281 (31 ) 367 AFUDC Equity (51 ) (144 ) (238 ) (369 ) Section 199 Domestic Production Activities Deduction (9 ) (362 ) (207 ) (1,087 ) Other Items – Net (231 ) (148 ) 141 (59 ) Income Tax Expense – Continuing Operations $ 5,163 $ 6,521 $ 15,738 $ 14,602 Effective Income Tax Rate – Continuing Operations 26.1 % 29.3 % 26.1 % 25.3 % |
Schedule of activity related to unrecognized tax benefits | (in thousands) 2016 2015 Balance on January 1 $ 468 $ 222 Increases Related to Tax Positions for Prior Years 40 236 Increases Related to Tax Positions for Current Year 26 131 Uncertain Positions Resolved During Year (97 ) — Balance on September 30 $ 437 $ 589 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations | For the Three Months Ended For the Nine Months Ended (in thousands) 2016 2015 2016 2015 Operating Revenues $ — $ — $ — $ 24,623 Operating Expenses (36 ) 420 (285 ) 31,770 Goodwill Impairment Charge — — — 1,000 Operating Income (Loss) 36 (420 ) 285 (8,147 ) Other Deductions — — — (42 ) Income Tax Expense (Benefit) 14 (168 ) 114 (2,873 ) Net Income (Loss) from Operations 22 (252 ) 171 (5,316 ) (Loss) Gain on Disposition Before Taxes — (108 ) — 11,425 Income Tax (Benefit) Expense on Disposition — (43 ) — 4,493 Net (Loss) Gain on Disposition — (65 ) — 6,932 Net Income (Loss) $ 22 $ (317 ) $ 171 $ 1,616 (in thousands) September, 30 December 31, Current Assets $ 249 $ — Assets of Discontinued Operations $ 249 $ — Current Liabilities $ 1,631 $ 2,098 Liabilities of Discontinued Operations $ 1,631 $ 2,098 |
Schedule of warranty reserves | (in thousands) 2016 2015 Warranty Reserve Balance, January 1 $ 2,103 $ 2,527 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year (24 ) (115 ) Decrease in Warranty Estimates for Prior Years (530 ) (100 ) Warranty Reserve Balance, September 30 $ 1,549 $ 2,312 |
Summary of Significant Accoun35
Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Level 1 | ||
Assets: | ||
Total Assets | $ 764 | $ 2,196 |
Level 1 | Money Market Deposit Escrow | ||
Assets: | ||
Money Market Escrow Accounts - AEV, Inc. and Foley Company Sales | 2,000 | |
Level 1 | Money Market and Mutual Funds | ||
Assets: | ||
Other Assets - Nonqualified Retirement Savings Plan | 764 | 196 |
Level 2 | ||
Assets: | ||
Total Assets | 7,914 | 8,093 |
Liabilities: | ||
Total Liabilities | 49 | 199 |
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | 3,506 | 4,235 |
Level 2 | Corporate Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | 4,408 | 3,858 |
Level 2 | Forward Gasoline Purchase Contracts | ||
Liabilities: | ||
Derivative Liabilities | $ 49 | $ 199 |
Summary of Significant Accoun36
Summary of Significant Accounting Policies - Inventories (Details 1) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Accounting Policies [Abstract] | ||
Finished Goods | $ 21,888 | $ 25,971 |
Work in Process | 13,774 | 12,821 |
Raw Material, Fuel and Supplies | 45,186 | 46,624 |
Total Inventories | $ 80,848 | $ 85,416 |
Summary of Significant Accoun37
Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 2) $ in Thousands | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2015 | $ 39,732 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2015 | 39,732 |
Adjustments to Goodwill in 2016 | (2,160) |
Balance (net of impairments) September 30, 2016 | 37,572 |
Manufacturing | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2015 | 20,430 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2015 | 20,430 |
Adjustments to Goodwill in 2016 | (2,160) |
Balance (net of impairments) September 30, 2016 | 18,270 |
Plastics | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2015 | 19,302 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2015 | 19,302 |
Adjustments to Goodwill in 2016 | |
Balance (net of impairments) September 30, 2016 | $ 19,302 |
Summary of Significant Accoun38
Summary of Significant Accounting Policies - Components of intangible assets (Details 3) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 23,081 | $ 22,999 |
Accumulated Amortization | 7,790 | 7,326 |
Net Carrying Amount | 15,291 | 15,673 |
Customer Relationships | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 22,491 | 21,681 |
Accumulated Amortization | 7,577 | 6,714 |
Net Carrying Amount | $ 14,914 | $ 14,967 |
Customer Relationships | Minimum | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods | 39 months | 48 months |
Customer Relationships | Maximum | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods | 227 months | 236 months |
Covenant not to Compete | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 590 | $ 620 |
Accumulated Amortization | 213 | 69 |
Net Carrying Amount | $ 377 | $ 551 |
Remaining Amortization Periods | 23 months | 32 months |
Other Intangible Assets | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 639 | |
Accumulated Amortization | 543 | |
Net Carrying Amount | $ 96 | |
Remaining Amortization Periods | 9 months | |
Emission Allowances | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 59 | |
Net Carrying Amount | $ 59 |
Summary of Significant Accoun39
Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 4) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Accounting Policies [Abstract] | ||||
Amortization Expense - Intangible Assets | $ 348 | $ 282 | $ 1,103 | $ 770 |
Summary of Significant Accoun40
Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 5) $ in Thousands | Sep. 30, 2016USD ($) |
Accounting Policies [Abstract] | |
2,016 | $ 1,436 |
2,017 | 1,330 |
2,018 | 1,264 |
2,019 | 1,133 |
2,020 | $ 1,099 |
Summary of Significant Accoun41
Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 6) - USD ($) $ in Thousands | Sep. 30, 2016 | Sep. 30, 2015 |
Noncash Investing Activities: | ||
Transactions Related to Capital Additions not Settled in Cash | $ 11,552 | $ 21,760 |
Summary of Significant Accoun42
Summary of Significant Accounting Policies - Effect of applying the guidance in ASU 2015-17 retrospectively to consolidated balance sheet (Details 7) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other Assets | $ 33,707 | $ 32,784 |
Unamortized Debt Expense | ||
Total Assets | 1,868,907 | 1,818,683 |
Current Liabilities | ||
Current Maturities of Long-Term Debt | 85,490 | 52,422 |
Total Current Liabilities | 246,256 | 271,116 |
Capitalization | ||
Long-Term Debt - Net | 460,757 | 443,846 |
Total Capitalization | 1,117,476 | 1,048,869 |
Total Liabilities and Equity | $ 1,868,907 | 1,818,683 |
Previously Stated | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other Assets | 31,108 | |
Unamortized Debt Expense | 3,897 | |
Total Assets | 1,820,904 | |
Current Liabilities | ||
Current Maturities of Long-Term Debt | 52,544 | |
Total Current Liabilities | 271,238 | |
Capitalization | ||
Long-Term Debt - Net | 445,945 | |
Total Capitalization | 1,050,968 | |
Total Liabilities and Equity | 1,820,904 | |
Adjustments | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Other Assets | 1,676 | |
Unamortized Debt Expense | (3,897) | |
Total Assets | (2,221) | |
Current Liabilities | ||
Current Maturities of Long-Term Debt | (122) | |
Total Current Liabilities | (122) | |
Capitalization | ||
Long-Term Debt - Net | (2,099) | |
Total Capitalization | (2,099) | |
Total Liabilities and Equity | $ (2,221) |
Summary of Significant Accoun43
Summary of Significant Accounting Policies (Detail Textuals) $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Significant Accounting Policies [Line Items] | |
Acquired goodwill | $ 8.2 |
Reduction in goodwill | $ 2.2 |
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company | |
Significant Accounting Policies [Line Items] | |
Amortization period | 52 months |
Percentage of development period costs, development fees and capital charge incurred by CCMC | 35.00% |
Amount of unrecovered development period costs, development fees and capital charges incurred by CCMC | $ 61.7 |
Maximum exposure to loss as a result of involvement with CCMC | $ 61.7 |
Business Combinations and Seg44
Business Combinations and Segment Information - Summary of major asset and liability category of BTD Georgia (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Assets: | ||
Goodwill | $ 37,572 | $ 39,732 |
BTD-Georgia | ||
Assets: | ||
Current Assets | 4,906 | |
Goodwill | 6,083 | |
Other Intangible Assets | 6,270 | |
Other Amortizable Assets | 1,380 | |
Fixed Assets | 13,649 | |
Total Assets | 32,288 | |
Liabilities: | ||
Current Liabilities | 2,971 | |
Lease Obligation | 11 | |
Total Liabilities | 2,982 | |
Cash Paid | $ 29,306 |
Business Combinations and Seg45
Business Combinations and Segment Information - Information on continuing operations for business segments (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Segment Reporting Information [Line Items] | ||||
Operating Revenue | $ 197,175 | $ 200,023 | $ 606,899 | $ 591,017 |
Interest Charges | 8,026 | 7,730 | 23,996 | 23,175 |
Income Tax Expense - Continuing Operations | 5,163 | 6,521 | 15,738 | 14,602 |
Net Income (Loss) | 14,616 | 15,392 | 44,811 | 44,763 |
Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Operating Revenue | (11) | (29) | (27) | (84) |
Corporate and Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Interest Charges | 475 | 504 | 1,484 | 1,542 |
Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Income Tax Expense - Continuing Operations | (1,326) | (1,301) | (3,722) | (4,068) |
Net Income (Loss) | (1,511) | (2,460) | (3,650) | (5,933) |
Discontinued Operations | ||||
Segment Reporting Information [Line Items] | ||||
Net Income (Loss) | 22 | (317) | 171 | 1,616 |
Electric | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Operating Revenue | 102,723 | 100,567 | 313,642 | 305,078 |
Interest Charges | 6,304 | 6,069 | 18,744 | 18,273 |
Income Tax Expense - Continuing Operations | 4,730 | 4,761 | 11,262 | 9,995 |
Net Income (Loss) | 12,513 | 12,921 | 34,199 | 34,351 |
Manufacturing | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Operating Revenue | 52,171 | 52,460 | 170,443 | 160,492 |
Interest Charges | 974 | 900 | 2,972 | 2,578 |
Income Tax Expense - Continuing Operations | 182 | 855 | 2,992 | 2,516 |
Net Income (Loss) | 1,246 | 1,714 | 6,108 | 4,810 |
Plastics | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Operating Revenue | 42,292 | 47,025 | 122,841 | 125,531 |
Interest Charges | 273 | 257 | 796 | 782 |
Income Tax Expense - Continuing Operations | 1,577 | 2,206 | 5,206 | 6,159 |
Net Income (Loss) | $ 2,346 | $ 3,534 | $ 7,983 | $ 9,919 |
Business Combinations and Seg46
Business Combinations and Segment Information - Total assets by business segment (Details 2) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Segment Reporting Information [Line Items] | ||
Assets | $ 1,868,907 | $ 1,818,683 |
Corporate | ||
Segment Reporting Information [Line Items] | ||
Assets | 37,432 | 42,312 |
Discontinued Operations | ||
Segment Reporting Information [Line Items] | ||
Assets | 249 | |
Electric | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | 1,575,790 | 1,520,887 |
Manufacturing | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | 168,705 | 173,860 |
Plastics | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 86,731 | $ 81,624 |
Business Combinations and Seg47
Business Combinations and Segment Information (Detail Textuals) - USD ($) $ in Thousands | Sep. 01, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 |
Business Acquisition [Line Items] | |||||
Cash | $ (1,500) | $ 30,806 | |||
Reduction in goodwill | $ 2,200 | ||||
Operating revenues | UNITED STATES | |||||
Business Acquisition [Line Items] | |||||
Operating revenues, percentage | 98.50% | 98.20% | 98.60% | 97.20% | |
BTD-Georgia | |||||
Business Acquisition [Line Items] | |||||
Cash | $ 30,800 | $ 29,300 | |||
Post closing reduction in purchase price | 1,500 | ||||
Reduction in goodwill | 2,200 | ||||
Amount of increase in customer relationships | 800 | ||||
Amount of increase in liabilities | $ 100 |
Business Combinations and Seg48
Business Combinations and Segment Information (Detail Textuals 1) | 9 Months Ended |
Sep. 30, 2016Segment | |
Acquisition And Segment Information [Abstract] | |
Number of reportable segments | 3 |
Rate and Regulatory Matters - S
Rate and Regulatory Matters - Summary of interim rate information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Sep. 30, 2016 | |
Public Utilities, General Disclosures [Line Items] | ||
Interim Revenue Increase (subject to refund) | $ 3,818 | $ 6,875 |
2016 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 |
Rate and Regulatory Matters -50
Rate and Regulatory Matters - Summary components of the requested rate increase (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2016 | Sep. 30, 2016 | |
Public Utilities, Rate Matters [Abstract] | ||
Approved Interim Revenue Increase (subject to refund), Amount | $ 3,818 | $ 6,875 |
2016 Test Year Allocation | ||
Public Utilities, Rate Matters [Abstract] | ||
Total Requested Revenue Increase, Amount | 19,296 | |
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset, Amount | (2,480) | |
Approved Interim Revenue Increase (subject to refund), Amount | 16,816 | |
2016 Test Year Allocation | Increased Rate Base | ||
Public Utilities, Rate Matters [Abstract] | ||
Total Requested Revenue Increase, Amount | 10,000 | |
2016 Test Year Allocation | Increased Expenses | ||
Public Utilities, Rate Matters [Abstract] | ||
Total Requested Revenue Increase, Amount | 7,700 | |
2016 Test Year Allocation | Other | ||
Public Utilities, Rate Matters [Abstract] | ||
Total Requested Revenue Increase, Amount | $ 1,596 |
Rate and Regulatory Matters -51
Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 2) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | $ 197,175 | $ 200,023 | $ 606,899 | $ 591,017 | |
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | [1] | 2,839 | 1,970 | 7,554 | 5,508 |
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 779 | 1,141 | 4,188 | 3,968 | |
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 3,127 | 2,565 | 9,362 | 7,722 | |
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 2,170 | 2,073 | 6,151 | 5,898 | |
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 1,950 | 1,565 | 6,155 | 4,912 | |
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 2,762 | 2,312 | 8,344 | 7,233 | |
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 135 | 234 | 418 | 464 | |
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | 335 | 267 | 1,397 | 911 | |
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | |||||
Regulatory Matters [Line Items] | |||||
Revenues recorded under rate riders | $ 691 | $ 461 | $ 1,951 | $ 1,484 | |
[1] | Includes MNCIP costs recovered in base rates. |
Rate and Regulatory Matters (De
Rate and Regulatory Matters (Detail Textuals) $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($)kVmi | |
Otter Tail Power Company | Big Stone South - Brookings MVP | |
Regulatory Matters [Line Items] | |
Project costs incurred to date | $ | $ 56.4 |
Percentage of assets of project | 100.00% |
Expanded capacity of projects | kV | 345 |
Extended distance of transmission line | mi | 70 |
Otter Tail Power Company | Big Stone South - Ellendale MVP | Minimum | |
Regulatory Matters [Line Items] | |
Extended distance of transmission line | mi | 160 |
Otter Tail Power Company | Big Stone South - Ellendale MVP | Maximum | |
Regulatory Matters [Line Items] | |
Extended distance of transmission line | mi | 170 |
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | |
Regulatory Matters [Line Items] | |
Project costs incurred to date | $ | $ 39.8 |
Percentage of assets of project | 100.00% |
Expanded capacity of projects | kV | 345 |
Big Stone AQCS Project BART - compliant AQCS | |
Regulatory Matters [Line Items] | |
Project costs incurred to date | $ | $ 199.3 |
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project | |
Regulatory Matters [Line Items] | |
Investment to acquire ownership interest | $ | $ 26.3 |
Percentage of ownership interest acquired in transmission line | 4.80% |
Distance of transmission line | mi | 250 |
Capacity Expansion 2020 | Otter Tail Power Company | Fargo-Monticello Project | |
Regulatory Matters [Line Items] | |
Investment to acquire ownership interest | $ | $ 81.5 |
Percentage of ownership interest acquired in transmission line | 14.20% |
Distance of transmission line | mi | 240 |
Percentage of assets of project | 100.00% |
Rate and Regulatory Matters (53
Rate and Regulatory Matters (Detail Textuals 1) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
Feb. 16, 2016 | Dec. 21, 2015 | Sep. 30, 2015 | Apr. 25, 2011 | Sep. 30, 2016 | Dec. 31, 2015 | May 25, 2016 | Apr. 14, 2016 | Apr. 01, 2016 | Jul. 09, 2015 | |
Otter Tail Power Company | Rebuttal Testimony | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Percentage of allowed rate of return on equity | 10.05% | |||||||||
Estimated Interim Rate Refund | $ 2.3 | |||||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Financial incentives recognized during period | $ 4.2 | |||||||||
Amount of financial incentive requested | $ 4.3 | |||||||||
Percentage Increase In Energy Savings | 39.00% | |||||||||
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% | |||||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Financial incentive request approved | $ 3 | |||||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Seeking revenue recovery | $ 7.2 | $ 7.8 | ||||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
General rate revenue increase requested | $ 5 | |||||||||
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 | ||||||||||
Regulatory Matters [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% | |||||||||
Increase to base rate portion of customer bills | 9.56% | |||||||||
MNDOC | Direct Testimony | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Percentage of allowed rate of return on equity | 8.86% | |||||||||
MNDOC | Rebuttal Testimony | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Percentage of allowed rate of return on equity | 8.66% | |||||||||
OAG | Direct Testimony | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Percentage of allowed rate of return on equity | 6.96% | |||||||||
OAG | Rebuttal Testimony | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Percentage of allowed rate of return on equity | 7.14% |
Rate and Regulatory Matters (54
Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - USD ($) $ in Millions | Sep. 01, 2016 | Mar. 31, 2016 | Aug. 31, 2015 | Jul. 31, 2015 | Mar. 31, 2015 | Jun. 22, 2016 | Nov. 25, 2009 |
Transmission Cost Recovery Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Jurisdictional capital and operating costs recovery | $ 8.5 | ||||||
Transmission Cost Recovery Rider | Fiscal Year 2016 | |||||||
Regulatory Matters [Line Items] | |||||||
Jurisdictional capital and operating costs recovery | $ 10.2 | ||||||
Revenue requirement | $ 5.7 | ||||||
Reduction Of Projected Over Collection | $ 2.6 | ||||||
Environmental Cost Recovery Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Percentage of ECR rider rate | 7.904% | 9.193% | 7.531% | ||||
Over collection of Big stone II abandoned plant costs | $ 10.4 | $ 12.2 | |||||
Renewable Resource Adjustment | |||||||
Regulatory Matters [Line Items] | |||||||
Percentage of allowed rate of return on equity | 10.50% | ||||||
2010 General Rate Case | |||||||
Regulatory Matters [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% |
Rate and Regulatory Matters (55
Rate and Regulatory Matters (Detail Textuals 3) - USD ($) | Feb. 12, 2015 | Nov. 06, 2014 | Nov. 12, 2013 | Sep. 28, 2016 | Aug. 31, 2016 | Dec. 22, 2015 | Aug. 31, 2015 | Apr. 21, 2011 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Jan. 01, 2012 |
Regulatory Matters [Line Items] | |||||||||||||
Regulatory Liabilities | $ 85,769,000 | $ 80,754,000 | |||||||||||
Otter Tail Power Company | South Dakota Public Utilities Commission | Environmental Cost Recovery Rider | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Annual revenue requesting recovery | $ 2,300,000 | $ 2,700,000 | |||||||||||
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case | |||||||||||||
Regulatory Matters [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 | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Percentage of prudently incurred costs of construction work in progress, authorized for recovery by formula transmission rate | 100.00% | ||||||||||||
Current return on equity used in transmission rates | 12.38% | 10.32% | |||||||||||
Proposed reduced return on equity used in transmission rates | 8.67% | 9.15% | |||||||||||
Additional Incentive Basis Point | 50-basis points | ||||||||||||
Reductions in revenue | $ 100,000 | $ 1,300,000 | $ 900,000 | ||||||||||
Expected percentage of return on equity | 10.82% | 9.70% | |||||||||||
Expected percentage of return on equity, description | ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) | ||||||||||||
Regulatory Liabilities | $ 2,400,000 |
Regulatory Assets and Liabili56
Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | $ 19,958 | $ 18,904 | |
Regulatory Liability - Current | 5,934 | 3,322 | |
Net Regulatory Assets Position - Current | 14,024 | 15,582 | |
Regulatory Assets - Long-Term | 118,123 | 127,707 | |
Regulatory Liabilities - Long-Term | 79,835 | 77,432 | |
Net Regulatory Asset Position - Long-Term | 38,288 | 50,275 | |
Regulatory Assets - Total | 138,081 | 146,611 | |
Regulatory Liabilities - Total | 85,769 | 80,754 | |
Net Regulatory Asset Position - Total | 52,312 | 65,857 | |
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | 7,439 | 7,439 |
Regulatory Assets - Long-Term | [1] | 94,671 | 99,293 |
Regulatory Assets - Total | [1] | $ 102,110 | $ 106,732 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
Deferred Marked-to-Market Loss | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | $ 4,063 | $ 4,063 |
Regulatory Assets - Long-Term | [1] | 7,483 | 10,530 |
Regulatory Assets - Total | [1] | $ 11,546 | $ 14,593 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 51 months | 60 months |
Conservation Improvement Program Costs and Incentives | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 4,286 | $ 4,411 |
Regulatory Assets - Long-Term | [2] | 3,079 | 4,266 |
Regulatory Assets - Total | [2] | $ 7,365 | $ 8,677 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 24 months | 18 months |
Accumulated ARO Accretion/Depreciation Adjustment | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | ||
Regulatory Assets - Long-Term | [1] | 6,031 | 5,672 |
Regulatory Assets - Total | [1] | $ 6,031 | $ 5,672 |
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 Asset - Current | [1] | $ 619 | $ 942 |
Regulatory Assets - Long-Term | [1] | 2,444 | 2,620 |
Regulatory Assets - Total | [1] | $ 3,063 | $ 3,562 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 55 months | 84 months |
Minnesota Transmission Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 576 | |
Regulatory Assets - Long-Term | [2] | ||
Regulatory Assets - Total | [2] | $ 576 | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | |
North Dakota Renewable Resource Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 1,608 | |
Regulatory Assets - Long-Term | [2] | 826 | 1,266 |
Regulatory Assets - Total | [2] | $ 2,434 | $ 1,266 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 18 months | 15 months |
Debt Reacquisition Premiums | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | $ 349 | $ 351 |
Regulatory Assets - Long-Term | [1] | 1,278 | 1,539 |
Regulatory Assets - Total | [1] | $ 1,627 | $ 1,890 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 192 months | 201 months |
Deferred Income Taxes | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | ||
Regulatory Liability - Current | |||
Regulatory Assets - Long-Term | [1] | 1,157 | 1,455 |
Regulatory Liabilities - Long-Term | 918 | 1,110 | |
Regulatory Assets - Total | [1] | 1,157 | 1,455 |
Regulatory Liabilities - Total | $ 918 | $ 1,110 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 474 | $ 698 |
Regulatory Liability - Current | |||
Regulatory Assets - Long-Term | [2] | 43 | 355 |
Regulatory Liabilities - Long-Term | 80 | ||
Regulatory Assets - Total | [2] | 517 | $ 1,053 |
Regulatory Liabilities - Total | $ 80 | ||
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 27 months | 24 months |
Regulatory Liabilities - Remaining Recovery/Refund Period | 27 months | ||
Big Stone II Unrecovered Project Costs - South Dakota | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 101 | $ 100 |
Regulatory Assets - Long-Term | [2] | 567 | 643 |
Regulatory Assets - Total | [2] | $ 668 | $ 743 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 80 months | 89 months |
North Dakota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | ||
Regulatory Assets - Long-Term | [2] | 544 | |
Regulatory Assets - Total | [2] | $ 544 | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 27 months | |
Minnesota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 370 | $ 777 | |
Regulatory Liabilities - Long-Term | |||
Regulatory Liabilities - Total | $ 370 | $ 777 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
Minnesota Renewable Resource Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 46 | |
Regulatory Assets - Long-Term | [2] | 68 | |
Regulatory Assets - Total | [2] | $ 46 | $ 68 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | see below | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | |||
Regulatory Liabilities - Long-Term | 77,603 | 74,948 | |
Regulatory Liabilities - Total | $ 77,603 | $ 74,948 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
North Dakota Renewable Resource Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 68 | ||
Regulatory Liabilities - Long-Term | |||
Regulatory Liabilities - Total | $ 68 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
Revenue for Rate Case expenses Subject to Refund - Minnesota | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 712 | ||
Regulatory Liabilities - Long-Term | 385 | 1,279 | |
Regulatory Liabilities - Total | $ 1,097 | $ 1,279 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 19 months | ||
Deferred Gain on Sale of Utility Property - Minnesota Portion | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 5 | ||
Regulatory Liabilities - Long-Term | 95 | ||
Regulatory Liabilities - Total | $ 100 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 216 months | ||
South Dakota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 296 | $ 185 | |
Regulatory Liabilities - Long-Term | |||
Regulatory Liabilities - Total | $ 296 | $ 185 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
Minnesota Deferred Rate Case Expenses Subject to Recovery | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [1] | $ 748 | $ 291 |
Regulatory Assets - Long-Term | [1] | ||
Regulatory Assets - Total | [1] | $ 748 | $ 291 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 12 months | 12 months |
South Dakota Transmission Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Asset - Current | [2] | $ 225 | $ 33 |
Regulatory Assets - Long-Term | [2] | ||
Regulatory Assets - Total | [2] | $ 225 | $ 33 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | 12 months |
Refundable Fuel Clause Adjustment Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 2,301 | $ 1,834 | |
Regulatory Liabilities - Long-Term | |||
Regulatory Liabilities - Total | $ 2,301 | $ 1,834 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
North Dakota Transmission Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 638 | $ 132 | |
Regulatory Liabilities - Long-Term | 758 | ||
Regulatory Liabilities - Total | $ 1,396 | $ 132 | |
Regulatory Assets - Remaining Recovery/Refund Period | 27 months | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 24 months | 12 months | |
North Dakota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 256 | $ 321 | |
Regulatory Liabilities - Long-Term | |||
Regulatory Liabilities - Total | $ 256 | $ 321 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
Minnesota Transmission Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 1,356 | ||
Regulatory Liabilities - Long-Term | 1,356 | ||
Regulatory Liabilities - Total | |||
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
Other | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liability - Current | $ 5 | ||
Regulatory Liabilities - Long-Term | 91 | ||
Regulatory Liabilities - Total | $ 96 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 207 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. |
Regulatory Assets and Liabili57
Regulatory Assets and Liabilities (Detail Textuals) | 9 Months Ended |
Sep. 30, 2016 | |
Debt Reacquisition Premiums | |
Schedule of Regulatory Assets and Liabilities [Line Items] | |
Regulatory assets - long term, remaining recovery/refund period | 192 months |
Open Contract Positions Subje58
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 | Sep. 30, 2016 | Dec. 31, 2015 |
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 | (15,220) | (16,070) |
Net Balance Subject to Legally Enforceable Netting Arrangements | $ (15,220) | $ (16,070) |
Open Contract Positions Subje59
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 4) - Otter Tail Power Company - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | |
Current Liability - Marked-to-Market Loss (in thousands) | |||
Loss Contracts Covered by Deposited Funds or Letters of Credit | $ 49 | $ 199 | |
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | [1] | 15,171 | 15,871 |
Loss Contracts with No Ratings Triggers or Deposit Requirements | |||
Loss Position | $ 15,220 | $ 16,070 | |
[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 $ 15,171 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,171 $ 15,871 |
Open Contract Positions Subje60
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 (Parenthetical) (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | |
Credit Derivatives [Line Items] | |||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | [1] | $ 15,171 | $ 15,871 |
Offsetting Gains with Counterparties under Master Netting Agreements | |||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $ 15,171 | $ 15,871 | |
[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 $ 15,171 $ 15,871 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 15,171 $ 15,871 |
Reconciliation of Common Shar61
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Balance, December 31, 2015 | $ 605,023 | |||
Common Stock Issuances, Net of Expenses | 41,456 | |||
Common Stock Retirements | (104) | |||
Net Income | $ 14,616 | $ 15,392 | 44,811 | $ 44,763 |
Other Comprehensive Income | 322 | |||
Employee Stock Incentive Plans Expense | 1,163 | |||
Common Dividends ($0.9375 per share) | (35,952) | |||
Balance, September 30, 2016 | 656,719 | 656,719 | ||
Common Shares | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Balance, December 31, 2015 | 189,286 | |||
Common Stock Issuances, Net of Expenses | 6,855 | |||
Common Stock Retirements | (18) | |||
Balance, September 30, 2016 | 196,123 | 196,123 | ||
Premium on Common Shares | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Balance, December 31, 2015 | 293,610 | |||
Common Stock Issuances, Net of Expenses | 34,601 | |||
Common Stock Retirements | (86) | |||
Employee Stock Incentive Plans Expense | 1,163 | |||
Balance, September 30, 2016 | 329,288 | 329,288 | ||
Retained Earnings | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Balance, December 31, 2015 | 126,025 | |||
Net Income | 44,811 | |||
Common Dividends ($0.9375 per share) | (35,952) | |||
Balance, September 30, 2016 | 134,884 | 134,884 | ||
Accumulated Other Comprehensive Income/(Loss) | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Balance, December 31, 2015 | (3,898) | |||
Other Comprehensive Income | 322 | |||
Balance, September 30, 2016 | $ (3,576) | $ (3,576) |
Reconciliation of Common Shar62
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) - $ / shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||||
Dividends Declared Per Common Share (in dollars per share) | $ 0.3125 | $ 0.3075 | $ 0.9375 | $ 0.9225 |
Reconciliation of Common Shar63
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1) | 9 Months Ended |
Sep. 30, 2016shares | |
Schedule Of Common Stock Outstanding [Roll Forward] | |
Common Shares Outstanding, December 31, 2015 | 37,857,186 |
Issuances: | |
At-the-Market Offering | 977,712 |
Automatic Dividend Reinvestment and Share Purchase Plan: | |
Dividends Reinvested | 131,111 |
Cash Invested | 79,494 |
Executive Stock Performance Awards (2013 and 2014 shares earned) | 54,700 |
Employee Stock Purchase Plan: | |
Cash Invested | 40,324 |
Dividends Reinvested | 19,090 |
Employee Stock Ownership Plan | 23,837 |
Restricted Stock Issued to Directors | 23,200 |
Vesting of Restricted Stock Units | 21,025 |
Directors Deferred Compensation | 542 |
Retirements: | |
Shares Withheld for Individual Income Tax Requirements | (3,668) |
Common Shares Outstanding, September 30, 2016 | 39,224,553 |
Reconciliation of Common Shar64
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 | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||||
Weighted Average Common Shares Outstanding - Basic | 38,832,659 | 37,575,413 | 38,316,324 | 37,417,283 |
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 | 103,084 | 141,540 | 80,450 | 141,540 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 48,645 | 44,280 | 42,620 | 44,280 |
Nonvested Restricted Shares | 18,029 | 31,079 | 14,556 | 31,079 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 3,289 | 2,231 | 3,451 | 2,231 |
Total Dilutive Shares | 173,047 | 219,130 | 141,077 | 219,130 |
Weighted Average Common Shares Outstanding - Diluted | 39,005,706 | 37,794,543 | 38,457,401 | 37,636,413 |
Reconciliation of Common Shar65
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | 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 | $ 0.01 | $ 0.01 | |
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS) | |||||
Stockholders Equity Note [Line Items] | |||||
Agreement To Sell Shares Value | $ 75 |
Share-Based Payments - Stock in
Share-Based Payments - Stock incentive awards to executive officers (Details) | 9 Months Ended |
Sep. 30, 2016$ / sharesshares | |
Stock Performance Awards | Executive Officers | February 4, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 81,500 |
Grant-Date Fair Value per Award | $ / shares | $ 24.03 |
Vesting Date | December 31, 2018 |
Restricted Stock Units | Executive Officers | February 4, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 22,000 |
Grant-Date Fair Value per Award | $ / shares | $ 28.915 |
Vesting Percentage | 25.00% |
Vesting Date | February 6, 2020 |
Restricted Stock Units | Key Employees | April 11, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 15,800 |
Grant-Date Fair Value per Award | $ / shares | $ 24 |
Vesting Percentage | 100.00% |
Vesting Date | April 8, 2020 |
Restricted Stock Units | Key Employees | September 21, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 1,420 |
Grant-Date Fair Value per Award | $ / shares | $ 30.59 |
Vesting Percentage | 100.00% |
Vesting Date | April 8, 2020 |
Restricted Stock | Nonemployee Directors | April 11, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 23,200 |
Grant-Date Fair Value per Award | $ / shares | $ 28.66 |
Vesting Percentage | 25.00% |
Vesting Date | April 8, 2020 |
Share-Based Payments - Amounts
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details 1) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | $ 778 | $ 160 | $ 2,447 | $ 2,343 |
Stock Performance Awards | Executive Officers | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | 455 | (142) | 1,296 | 915 |
Restricted Stock Units (RSUs) | Executive Officers | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | 64 | 36 | 373 | 416 |
Restricted Stock Units (RSUs) | Nonexecutive Employees | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | 62 | 86 | 207 | 233 |
Restricted Stock | Executive Officers | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | 22 | 29 | 73 | 330 |
Restricted Stock | Directors | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | 128 | 107 | 363 | 311 |
Employee Stock Purchase Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense | $ 47 | $ 44 | $ 135 | $ 138 |
Share-Based Payments - Amount68
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details 1) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Employee Stock Purchase Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Stock compensation expense, discount rate | 15.00% | 15.00% | 15.00% | 15.00% |
Share-Based Payments (Detail Te
Share-Based Payments (Detail Textuals) $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized compensation expense related to stock-based compensation | $ | $ 5.1 |
Weighted-average period of amortization | 2 years 4 months 24 days |
Stock Performance Awards | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Targeted aggregate common shares award | 81,500 |
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 | 122,250 |
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 | 54,333 |
Targeted aggregate common shares award return on equity component | 27,167 |
Period specified for average adjusted return | 3 years |
Retained Earnings Restriction (
Retained Earnings Restriction (Detail Textuals) - USD ($) | 9 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | |
Retained Earnings Restriction [Line Items] | ||
Equity to total capitalization ratio | 52.90% | |
Total Capitalization | $ 1,117,476,000 | $ 1,048,869,000 |
OTP | ||
Retained Earnings Restriction [Line Items] | ||
Total Capitalization | $ 1,123,168,000 | |
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% |
Commitments and Contingencies (
Commitments and Contingencies (Detail Textuals) - USD ($) | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | Sep. 27, 2016 | |
Commitments and Contingencies Disclosure [Line Items] | |||
Loss contingency, range of possible loss, maximum | $ 1,000,000 | ||
Otter Tail Power Company | Federal Energy Regulatory Commission | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Estimated liability of refund obligation | $ 2,400,000 | ||
Otter Tail Power Company | Coal Purchase Commitments | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Contracts expiration year | 2017 and 2040 | ||
Otter Tail Power Company | Electric utility capacity | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | $ 3,500,000 | ||
Otter Tail Power Company | Construction Programs | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | $ 137,400,000 | $ 89,600,000 | |
Otter Tail Power Company | Operating lease | Rail cars used for transport of coal | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Operating Leases | $ 970,000 |
Short-Term and Long-Term Borr72
Short-Term and Long-Term Borrowings - Status of lines of credit (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | ||
Line Limit | $ 320,000 | |
In Use | 37,173 | |
Restricted due to Outstanding Letters of Credit | 50 | |
Available | 282,777 | $ 239,028 |
Otter Tail Corporation Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 150,000 | |
Available | 150,000 | 90,334 |
OTP Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 170,000 | |
In Use | 37,173 | |
Restricted due to Outstanding Letters of Credit | 50 | |
Available | $ 132,777 | $ 148,694 |
Short-Term and Long-Term Borr73
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Short-Term Debt | $ 37,173 | $ 80,672 |
Long-Term Debt | 548,329 | 498,489 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 85,490 | 52,422 |
Unamortized Debt Issuance Costs | 2,082 | 2,221 |
Long-Term Debt - Net | 460,757 | 443,846 |
Total Short-Term and Long-Term Debt (with current maturities) | 583,420 | 576,940 |
9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 52,330 | 52,330 |
Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 50,000 | |
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 | 126 | 182 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 873 | 977 |
OTP | ||
Debt Instrument [Line Items] | ||
Short-Term Debt | 37,173 | 21,006 |
Long-Term Debt | 445,000 | 445,000 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 32,958 | |
Unamortized Debt Issuance Costs | 1,920 | 2,099 |
Long-Term Debt - Net | 410,122 | 442,901 |
Total Short-Term and Long-Term Debt (with current maturities) | 480,253 | 463,907 |
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 | 59,666 | |
Long-Term Debt | 103,329 | 53,489 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 52,532 | 52,422 |
Unamortized Debt Issuance Costs | 162 | 122 |
Long-Term Debt - Net | 50,635 | 945 |
Total Short-Term and Long-Term Debt (with current maturities) | 103,167 | 113,033 |
Otter Tail Corporation | 9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 52,330 | 52,330 |
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 50,000 | |
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 126 | 182 |
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | $ 873 | $ 977 |
Short-Term and Long-Term Borr74
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details 1) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 9.00% | 9.00% |
Long-Term Debt, Due Date | Dec. 15, 2016 | Dec. 15, 2016 |
Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 0.90% | |
Long-Term Debt, Due Date | Feb. 5, 2018 | |
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. 1, 2021 | Dec. 1, 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. 1, 2018 | Apr. 1, 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. 1, 2021 | Dec. 1, 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 | 9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 9.00% | 9.00% |
Long-Term Debt, Due Date | Dec. 15, 2016 | Dec. 15, 2016 |
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 0.90% | |
Long-Term Debt, Due Date | Feb. 5, 2018 | |
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. 1, 2018 | Apr. 1, 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 |
Short-Term and Long-Term Borr75
Short-Term and Long-Term Borrowings (Detail Textuals) - USD ($) | 9 Months Ended | ||
Sep. 30, 2016 | Oct. 31, 2016 | Sep. 23, 2016 | |
Debt Instrument [Line Items] | |||
Line Limit | $ 320,000,000 | ||
Otter Tail Corporation Credit Agreement | |||
Debt Instrument [Line Items] | |||
Line Limit | $ 150,000,000 | ||
Otter Tail Corporation Credit Agreement | Subsequent Event | |||
Debt Instrument [Line Items] | |||
Line Limit | $ 130,000,000 | ||
2016 Note Purchase Agreement | |||
Debt Instrument [Line Items] | |||
Debt instrument description of prepayment | The 2016 Note Purchase Agreement states the Company 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 the Company of all of the 2026 Notes on or after September 15, 2026 will be made without any make-whole amount. | ||
Priority debt maximum percentage of total capitalization | 10.00% | ||
Financial covenants of debt | The Company may not permit the ratio of its Interest-bearing Debt (as defined in the 2016 Note Purchase Agreement) to Total Capitalization (as defined in the 2016 Note Purchase Agreement) to be greater than 0.60 to 1.00, determined as of the end of each fiscal quarter, and may not permit the Interest and Dividend Coverage Ratio (as defined in the 2016 Note Purchase Agreement) to be less than 1.50 to 1.00 for any period of four consecutive fiscal quarters. The Company is also restricted from allowing its Priority Debt (as defined in the 2016 Note Purchase Agreement) to exceed 10% of Total Capitalization, determined as of the end of each fiscal quarter. | ||
2016 Note Purchase Agreement | Minimum | |||
Debt Instrument [Line Items] | |||
Debt to total capitalization ratio | 0.60 | ||
Interest and dividend coverage ratio | 1 | ||
2016 Note Purchase Agreement | Maximum | |||
Debt Instrument [Line Items] | |||
Debt to total capitalization ratio | 1 | ||
Interest and dividend coverage ratio | 1.50 | ||
2016 Note Purchase Agreement | Guaranteed Senior Notes due December 15, 2026 | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount of note | $ 52,330,000 | $ 80,000,000 | |
Debt instrument, interest rate | 9.00% | 3.55% |
Short-Term and Long-Term Borr76
Short-Term and Long-Term Borrowings (Detail Textuals 1) $ in Thousands | Feb. 05, 2016USD ($) | Sep. 30, 2016USD ($) |
Debt Instrument [Line Items] | ||
Aggregate commitment of loan | $ 320,000 | |
Term Loan Agreement | JPMorgan | ||
Debt Instrument [Line Items] | ||
Aggregate commitment of loan | $ 50,000 | |
Minimum increments tranches of term loans | 10,000 | |
Maximum amount of debt outstanding | 100,000 | |
Borrowed amount | $ 50,000 | |
Interest rate base | LIBOR plus 0.90% | |
Term Loan Agreement | JPMorgan | LIBOR | ||
Debt Instrument [Line Items] | ||
Line of credit facility, description of variable rate basis | LIBOR | |
Basis spread on variable rate | 0.90% | |
Term Loan Agreement | JPMorgan | Prime Rate | ||
Debt Instrument [Line Items] | ||
Line of credit facility, description of variable rate basis | Prime Rate | |
Term Loan Agreement | JPMorgan | Federal Reserve Bank of New York Rate | ||
Debt Instrument [Line Items] | ||
Line of credit facility, description of variable rate basis | Federal Reserve Bank of New York Rate | |
Basis spread on variable rate | 0.50% | |
Term Loan Agreement | JPMorgan | Statutory Reserve Rate | ||
Debt Instrument [Line Items] | ||
Line of credit facility, description of variable rate basis | LIBOR multiplied by the Statutory Reserve Rate | |
Basis spread on variable rate | 1.00% | |
Term Loan Agreement | Minimum | JPMorgan | ||
Debt Instrument [Line Items] | ||
Debt to total capitalization ratio | 0.60 | |
Interest and dividend coverage ratio | 1 | |
Term Loan Agreement | Maximum | JPMorgan | ||
Debt Instrument [Line Items] | ||
Debt to total capitalization ratio | 1 | |
Interest and dividend coverage ratio | 1.50 |
Pension Plan and Other Postre77
Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service Cost - Benefit Earned During the Period | $ 1,376 | $ 1,514 | $ 4,139 | $ 4,544 | |
Interest Cost on Projected Benefit Obligation | 3,603 | 3,336 | 10,646 | 10,008 | |
Expected Return on Assets | (4,857) | (4,595) | (14,590) | (13,787) | |
Amortization of Prior-Service Cost: | |||||
From Regulatory Asset | 48 | 47 | 142 | 141 | |
From Other Comprehensive Income | [1] | 1 | 2 | 3 | 4 |
Amortization of Net Actuarial Loss: | |||||
From Regulatory Asset | 1,411 | 1,669 | 3,865 | 5,007 | |
From Other Comprehensive Income | [1] | 32 | 42 | 95 | 128 |
Net Periodic Cost | 1,614 | 2,015 | 4,300 | 6,045 | |
Executive Survivor and Supplemental Retirement Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service Cost - Benefit Earned During the Period | 63 | 48 | 189 | 142 | |
Interest Cost on Projected Benefit Obligation | 417 | 380 | 1,251 | 1,142 | |
Amortization of Prior-Service Cost: | |||||
From Regulatory Asset | 4 | 5 | 12 | 13 | |
From Other Comprehensive Income | [2] | 9 | 9 | 28 | 28 |
Amortization of Net Actuarial Loss: | |||||
From Regulatory Asset | 74 | 83 | 220 | 250 | |
From Other Comprehensive Income | [3] | 111 | 151 | 334 | 452 |
Net Periodic Cost | 678 | 676 | 2,034 | 2,027 | |
Postretirement Benefits | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service Cost - Benefit Earned During the Period | 365 | 324 | 976 | 972 | |
Interest Cost on Projected Benefit Obligation | 794 | 524 | 1,877 | 1,573 | |
Amortization of Prior-Service Cost: | |||||
From Regulatory Asset | 34 | 52 | 100 | 154 | |
From Other Comprehensive Income | [1] | 1 | 1 | 3 | 4 |
Amortization of Net Actuarial Loss: | |||||
From Regulatory Asset | 284 | 284 | |||
From Other Comprehensive Income | [1] | 7 | 7 | ||
Net Periodic Cost | 1,485 | 901 | 3,247 | 2,703 | |
Effect of Medicare Part D Subsidy | $ (177) | $ (372) | $ (692) | $ (1,115) | |
[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 $ 3 $ 3 $ 11 $ 11 Other Nonelectric Expenses 6 6 17 17 | ||||
[3] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 68 $ 78 $ 204 $ 233 Other Nonelectric Expenses 43 73 130 219 |
Pension Plan and Other Postre78
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 | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Defined Benefit Plan Disclosure [Line Items] | |||||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | [1] | $ 9 | $ 9 | $ 28 | $ 28 |
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | [2] | 111 | 151 | 334 | 452 |
Electric operation and maintenance expenses | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | 3 | 3 | 11 | 11 | |
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | 68 | 78 | 204 | 233 | |
Other nonelectric expenses | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | 6 | 6 | 17 | 17 | |
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | $ 43 | $ 73 | $ 130 | $ 219 | |
[1] | Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 3 $ 3 $ 11 $ 11 Other Nonelectric Expenses 6 6 17 17 | ||||
[2] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 68 $ 78 $ 204 $ 233 Other Nonelectric Expenses 43 73 130 219 |
Pension Plan and Other Postre79
Pension Plan and Other Postretirement Benefits (Detail Textuals) - USD ($) | 1 Months Ended | |
Jan. 31, 2016 | Jan. 31, 2015 | |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discretionary plan contributions | $ 10,000,000 | $ 10,000,000 |
Fair Value of Financial Instr80
Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Carrying Amount | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Short-Term Debt | $ (37,173) | $ (80,672) |
Long-Term Debt including Current Maturities | (546,247) | (496,268) |
Fair Value | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Short-Term Debt | (37,173) | (80,672) |
Long-Term Debt including Current Maturities | $ (618,875) | $ (561,245) |
Fair Value of Financial Instr81
Fair Value of Financial Instruments (Detail Textuals) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2016 | Dec. 31, 2015 | |
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% |
Income Tax Expense - Continui82
Income Tax Expense - Continuing operations effective income tax rate (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | ||||
Income Before Income Taxes - Continuing Operations | $ 19,757 | $ 22,230 | $ 60,378 | $ 57,749 |
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%) | 7,705 | 8,670 | 23,547 | 22,522 |
Increases (Decreases) in Tax from: | ||||
Federal Production Tax Credits | (1,423) | (1,437) | (4,994) | (5,147) |
R&D Tax Credits | (223) | 2 | (445) | (7) |
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes | (212) | (212) | (637) | (637) |
Employee Stock Ownership Plan Dividend Deduction | (157) | (171) | (472) | (514) |
Corporate Owned Life Insurance | (92) | 185 | (664) | (39) |
Investment Tax Credits | (87) | (143) | (262) | (428) |
Adjustment for Uncertain Tax Positions | (57) | 281 | (31) | 367 |
AFUDC Equity | (51) | (144) | (238) | (369) |
Section 199 Domestic Production Activities Deduction | (9) | (362) | (207) | (1,087) |
Other Items - Net | (231) | (148) | 141 | (59) |
Income Tax Expense - Continuing Operations | $ 5,163 | $ 6,521 | $ 15,738 | $ 14,602 |
Effective Income Tax Rate - Continuing Operations | 26.10% | 29.30% | 26.10% | 25.30% |
Income Tax Expense - Continui83
Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | ||||
Composite Federal and State Statutory Rate | 39.00% | 39.00% | 39.00% | 39.00% |
Income Tax Expense - Continui84
Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance on January 1 | $ 468 | $ 222 |
Increases Related to Tax Positions for Prior Years | 40 | 236 |
Increases Related to Tax Positions for Current Year | 26 | 131 |
Uncertain Positions Resolved During Year | (97) | |
Balance on September 30 | $ 437 | $ 589 |
Discontinued Operations - Resul
Discontinued Operations - Results of discontinued operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | $ 171 | $ (5,316) | ||
Income Tax (Benefit) Expense on Disposition | $ (43) | 4,493 | ||
Net (Loss) Gain on Disposition | (65) | 6,932 | ||
Net Income (Loss) | $ 22 | (317) | 171 | 1,616 |
Disposal groups held for sale or disposed of by sale | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Operating Revenues | 24,623 | |||
Operating Expenses | (36) | 420 | (285) | 31,770 |
Goodwill Impairment Charge | 1,000 | |||
Operating Income (Loss) | 36 | (420) | 285 | (8,147) |
Other Deductions | (42) | |||
Income Tax Expense (Benefit) | 14 | (168) | 114 | (2,873) |
Net Income (Loss) from Operations | 22 | (252) | 171 | (5,316) |
(Loss) Gain on Disposition Before Taxes | (108) | 11,425 | ||
Income Tax (Benefit) Expense on Disposition | (43) | 4,493 | ||
Net (Loss) Gain on Disposition | (65) | 6,932 | ||
Net Income (Loss) | $ 22 | $ (317) | $ 171 | $ 1,616 |
Discontinued Operations - Major
Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Current Assets | $ 249 | |
Liabilities of Discontinued Operations | 1,631 | $ 2,098 |
Disposal groups held for sale or disposed of by sale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Current Assets | 249 | |
Assets of Discontinued Operations | 249 | |
Current Liabilities | 1,631 | 2,098 |
Liabilities of Discontinued Operations | $ 1,631 | $ 2,098 |
Discontinued Operations - Warra
Discontinued Operations - Warranty Reserves (Details 2) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Movement in Standard Product Warranty Accrual [Roll Forward] | ||
Warranty Reserve Balance, January 1 | $ 2,103 | $ 2,527 |
Additional Provision for Warranties Made During the Year | ||
Settlements Made During the Year | (24) | (115) |
Decrease in Warranty Estimates for Prior Years | (530) | (100) |
Warranty Reserve Balance, September 30 | $ 1,549 | $ 2,312 |
Discontinued Operations (Detail
Discontinued Operations (Detail Textuals) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | $ 171 | $ (5,316) | ||
Waterfront equipment manufacturer | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | (600) | |||
Wind tower manufacturer | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | 200 | |||
Foley | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | (4,100) | |||
AEV, Inc. | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | (800) | |||
Disposal groups held for sale or disposed of by sale | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Net Income (Loss) from Operations | $ 22 | $ (252) | $ 171 | (5,316) |
Disposal groups held for sale or disposed of by sale | Foley | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Cost estimates pretax charges | $ 4,400 |