Document And Entity Information
Document And Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | Apr. 30, 2018 | |
Document Information [Line Items] | ||
Entity Registrant Name | Otter Tail Corp | |
Entity Central Index Key | 1,466,593 | |
Trading Symbol | ottr | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Current Reporting Status | Yes | |
Entity Voluntary Filers | No | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Common Stock, Shares Outstanding (in shares) | 39,651,236 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false |
Consolidated Balance Sheets (Cu
Consolidated Balance Sheets (Current Period Not Audited) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and Cash Equivalents | $ 1,121 | $ 16,216 |
Accounts Receivable: | ||
Trade—Net | 94,265 | 68,466 |
Other | 7,109 | 7,761 |
Inventories | 87,999 | 88,034 |
Unbilled Receivables | 18,692 | 22,427 |
Income Taxes Receivable | 1,181 | |
Regulatory Assets | 19,736 | 22,551 |
Other | 11,210 | 12,491 |
Total Current Assets | 240,132 | 239,127 |
Investments | 8,648 | 8,629 |
Other Assets | 35,763 | 36,006 |
Goodwill | 37,572 | 37,572 |
Other Intangibles—Net | 13,420 | 13,765 |
Regulatory Assets | 125,667 | 129,576 |
Plant | ||
Electric Plant in Service | 1,986,385 | 1,981,018 |
Nonelectric Operations | 219,942 | 216,937 |
Construction Work in Progress | 153,963 | 141,067 |
Total Gross Plant | 2,360,290 | 2,339,022 |
Less Accumulated Depreciation and Amortization | 814,074 | 799,419 |
Net Plant | 1,546,216 | 1,539,603 |
Total Assets | 2,007,418 | 2,004,278 |
Current Liabilities | ||
Short-Term Debt | 30,319 | 112,371 |
Current Maturities of Long-Term Debt | 171 | 186 |
Accounts Payable | 87,179 | 84,185 |
Accrued Salaries and Wages | 14,806 | 21,534 |
Accrued Federal and State Income Taxes | 984 | |
Accrued Taxes | 17,585 | 16,808 |
Regulatory Liabilities | 5,119 | 9,688 |
Other Accrued Liabilities | 9,940 | 11,389 |
Liabilities of Discontinued Operations | 492 | |
Total Current Liabilities | 166,103 | 256,653 |
Pensions Benefit Liability | 89,552 | 109,708 |
Other Postretirement Benefits Liability | 70,040 | 69,774 |
Other Noncurrent Liabilities | 23,482 | 22,769 |
Commitments and Contingencies (note 8) | ||
Deferred Credits | ||
Deferred Income Taxes | 103,009 | 100,501 |
Deferred Tax Credits | 21,025 | 21,379 |
Regulatory Liabilities - Long -Term | 233,279 | 232,893 |
Other | 2,935 | 3,329 |
Total Deferred Credits | 360,248 | 358,102 |
Capitalization | ||
Long-Term Debt—Net | 589,943 | 490,380 |
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2018—39,626,594 Shares; 2017—39,557,491 Shares | 198,133 | 197,787 |
Premium on Common Shares | 341,841 | 343,450 |
Retained Earnings | 174,209 | 161,286 |
Accumulated Other Comprehensive Loss | (6,133) | (5,631) |
Total Common Equity | 708,050 | 696,892 |
Total Capitalization | 1,297,993 | 1,187,272 |
Total Liabilities and Equity | 2,007,418 | 2,004,278 |
Cumulative Preferred Shares [Member] | ||
Capitalization | ||
Cumulative Shares | ||
Cumulative Preference Shares [Member] | ||
Capitalization | ||
Cumulative Shares |
Consolidated Balance Sheets (C3
Consolidated Balance Sheets (Current Period Not Audited) (Parentheticals) - $ / shares | Mar. 31, 2018 | Dec. 31, 2017 |
Common shares, par value (in dollars per share) | $ 5 | $ 5 |
Common shares, authorized (in shares) | 50,000,000 | 50,000,000 |
Common shares, outstanding (in shares) | 39,626,594 | 39,557,491 |
Cumulative Preferred Shares [Member] | ||
Cumulative shares, authorized (in shares) | 1,500,000 | 1,500,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding (in shares) | 0 | 0 |
Cumulative Preference Shares [Member] | ||
Cumulative shares, authorized (in shares) | 1,000,000 | 1,000,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding (in shares) | 0 | 0 |
Consolidated Statements of Inco
Consolidated Statements of Income (Not Audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Operating Revenues: | ||
Operating Revenues | $ 241,266 | $ 214,117 |
Operating Expenses | ||
Production Fuel – Electric | 18,706 | 16,382 |
Cost of Products Sold (depreciation included below) | 88,785 | 75,277 |
Electric Operation and Maintenance Expenses | 39,475 | 37,277 |
Other Nonelectric Expenses | 12,494 | 10,135 |
Depreciation and Amortization | 18,763 | 17,854 |
Property Taxes – Electric | 3,835 | 3,798 |
Total Operating Expenses | 203,651 | 179,911 |
Operating Income | 37,615 | 34,206 |
Interest Charges | 7,372 | 7,462 |
Nonservice Cost Components of Postretirement Benefits | 1,417 | 1,405 |
Other Income | 1,183 | 553 |
Income Before Income Taxes – Continuing Operations | 30,009 | 25,892 |
Income Tax Expense – Continuing Operations | 3,794 | 6,363 |
Net Income from Continuing Operations | 26,215 | 19,529 |
Income from Discontinued Operations – net of Income Tax Expense of $38 in 2017 | 56 | |
Net Income | $ 26,215 | $ 19,585 |
Average Number of Common Shares Outstanding—Basic (in shares) | 39,550,874 | 39,350,802 |
Average Number of Common Shares Outstanding—Diluted (in shares) | 39,863,682 | 39,640,725 |
Basic Earnings Per Common Share: | ||
Continuing Operations (in dollars per share) | $ 0.66 | $ 0.50 |
Discontinued Operations (in dollars per share) | ||
(in dollars per share) | 0.66 | 0.50 |
Diluted Earnings Per Common Share: | ||
Continuing Operations (in dollars per share) | 0.66 | 0.49 |
Discontinued Operations (in dollars per share) | ||
(in dollars per share) | 0.66 | 0.49 |
Dividends Declared Per Common Share (in dollars per share) | $ 0.335 | $ 0.32 |
Electricity [Member] | ||
Operating Revenues: | ||
Revenues from Contracts with Customers | $ 123,825 | $ 119,782 |
Changes in Accrued Revenues under Alternative Revenue Programs | (875) | (1,239) |
Operating Revenues | 122,950 | 118,543 |
Product [Member] | ||
Operating Revenues: | ||
Revenues from Contracts with Customers | 118,316 | 95,574 |
Electricity, Purchased [Member] | ||
Operating Expenses | ||
Cost of Products Sold (depreciation included below) | $ 21,593 | $ 19,188 |
Consolidated Statements of Inc5
Consolidated Statements of Income (Not Audited) (Parentheticals) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Tax Expense - Discontinued Operations | $ 38 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Net Income | $ 26,215 | $ 19,585 |
Unrealized Gains on Available-for-Sale Securities: | ||
Reversal of Previously Recognized Gains on Available for Sale Securities Included in Other Income During Period | (110) | |
Unrealized (Losses) Gains Arising During Period | (66) | 17 |
Income Tax Benefit (Expense) | 37 | (6) |
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | (139) | 11 |
Pension and Postretirement Benefit Plans: | ||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10) | 227 | 157 |
Income Tax Expense | (59) | (63) |
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act | (531) | |
Pension and Postretirement Benefit Plans – net-of-tax | (363) | 94 |
Total Other Comprehensive (Loss) Income | (502) | 105 |
Total Comprehensive Income | $ 25,713 | $ 19,690 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Cash Flows from Operating Activities | ||
Net Income | $ 26,215 | $ 19,585 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Net Income from Discontinued Operations | (56) | |
Depreciation and Amortization | 18,763 | 17,854 |
Deferred Tax Credits | (354) | (366) |
Deferred Income Taxes | 2,901 | 4,512 |
Change in Deferred Debits and Other Assets | 6,295 | 5,005 |
Discretionary Contribution to Pension Plan | (20,000) | |
Change in Noncurrent Liabilities and Deferred Credits | (5,091) | 1,314 |
Allowance for Equity/Other Funds Used During Construction | (638) | (170) |
Stock Compensation Expense—Equity Awards | 1,146 | 1,150 |
Other—Net | (284) | (5) |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (25,047) | (15,521) |
Change in Inventories | 35 | 2,267 |
Change in Other Current Assets | 2,334 | (22) |
Change in Payables and Other Current Liabilities | (2,598) | (13,986) |
Change in Interest and Income Taxes Receivable/Payable | 1,163 | (321) |
Net Cash Provided by Continuing Operations | 4,840 | 21,240 |
Net Cash Used in Discontinued Operations | (200) | (39) |
Net Cash Provided by Operating Activities | 4,640 | 21,201 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (23,618) | (30,113) |
Net Proceeds from Disposal of Noncurrent Assets | 510 | 612 |
Cash Used for Investments and Other Assets | (719) | (508) |
Net Cash Used in Investing Activities | (23,827) | (30,009) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | 2,338 | 7,999 |
Net Short-Term (Repayments) Borrowings | (82,052) | 16,293 |
Proceeds from Issuance of Common Stock – net of Issuance Expenses | 1,958 | |
Payments for Retirement of Capital Stock | (2,409) | (1,759) |
Proceeds from Issuance of Long-Term Debt | 100,000 | |
Short-Term and Long-Term Debt Issuance Expenses | (433) | |
Payments for Retirement of Long-Term Debt | (60) | (3,057) |
Dividends Paid | (13,292) | (12,626) |
Net Cash Provided by Financing Activities | 4,092 | 8,808 |
Net Change in Cash and Cash Equivalents | (15,095) | |
Cash and Cash Equivalents at Beginning of Period | 16,216 | |
Cash and Cash Equivalents at End of Period | $ 1,121 |
Note 1 - Summary of Significant
Note 1 - Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Significant Accounting Policies and New Accounting Pronouncements [Text Block] | 1. Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 2018 2017. Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 December 31, 2017: March 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,220 Corporate Debt Securities – Held by Captive Insurance Company $ 5,341 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,779 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 870 Total Assets $ 2,090 $ 7,120 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company third may Coyote Station Lignite Supply Agreement – Variable Interest Entity October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2018 $56.5 35% Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2018 2017 Finished Goods $ 25,341 $ 26,605 Work in Process 17,224 14,222 Raw Material, Fuel and Supplies 45,434 47,207 Total Inventories $ 87,999 $ 88,034 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first three 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) March 31, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2018 December 31, 2017: March 31 , 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,277 $ 13,214 21 - 209 Covenant not to Compete 590 508 82 5 Other 154 30 124 29 Total $ 23,235 $ 9,815 $ 13,420 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 332 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,451 $ 10,811 New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 . 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01are December 15, 2017, 2016 01 first 2018, March 31, 2018 $1,220,000 first 2018 $87,000. ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three March 31, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. ASU 201 8 - 0 2 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $784,000 |
Note 2 - Segment Information
Note 2 - Segment Information | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Segment Reporting Disclosure [Text Block] | 2. Segment Information Segment Information The accounting policies of the segments are described under note 1 three three Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not No 10% 2017. one 11.7% 2017 one 24.3% 2017 one 12.0% 2017 two 20.6% 17.8% 2017 one All of the Company’s long-lived assets are within the United States and 98.3% 98.4% three March 31, 2018 2017 The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three March 31, 2018 2017 March 31, 2018 December 31, 2017 Operating Revenue Three Months Ended March 31, (in thousands) 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 109,180 $ 106,454 Changes in Accrued ARP Revenues (875 ) (1,239 ) Total Retail Sales Revenue 108,305 105,215 Wholesale Revenues – Company Generation 1,015 867 Other Revenues 13,645 12,469 Total Electric Segment Revenues $ 122,965 $ 118,551 Manufacturing Segment: Metal Parts and Tooling $ 56,927 $ 48,078 Plastic Products 10,235 9,552 Other 1,500 787 Total Manufacturing Segment Revenues $ 68,662 $ 58,417 Plastics Segment – Sale of PVC Pipe Products $ 49,653 $ 37,157 Intersegment Eliminations $ (14 ) $ (8 ) Total $ 241,266 $ 214,117 Interest Charges Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 6,390 $ 6,386 Manufacturing 554 554 Plastics 150 153 Corporate and Intersegment Eliminations 278 369 Total $ 7,372 $ 7,462 Income Taxes Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 2,098 $ 6,062 Manufacturing 1,223 1,055 Plastics 2,414 1,390 Corporate (1,941 ) (2,144 ) Total $ 3,794 $ 6,363 Net Income (Loss) Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 16,668 $ 15,560 Manufacturing 4,164 2,172 Plastics 6,844 2,437 Corporate (1,461 ) (640 ) Discontinued Operations -- 56 Total $ 26,215 $ 19,585 Identifiable Assets March 31, December 31, (in thousands) 2018 2017 Electric $ 1,686,255 $ 1,690,224 Manufacturing 180,319 167,023 Plastics 97,953 87,230 Corporate 42,891 59,801 Total $ 2,007,418 $ 2,004,278 |
Note 3 - Rate and Regulatory Ma
Note 3 - Rate and Regulatory Matters | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Public Utilities Disclosure [Text Block] | 3. Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2018 2017. Major Capital Expenditure Projects Big Stone South–Ellendale Multi-Value Transmission Project (MVP) 345 163 December 2011. second 2016 2019. March 31, 2018 $96.5 100% Big Stone South–Brookings MVP 345 70 December 2011. third 2015 September 8, 2017. March 31, 2018 $72.4 100% Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota General Rate s 2016 March 2017 May 1, 2017. 8.61% 7.5056% 10.74% 9.41%. The MPUC’s order also included: ( 1 2 OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 November 17, 2017. 1 2 9.41% 2016 April 16, 2016, October 31, 2017, $0.9 $1.4 12 November 1, 2017, Minnesota Conservation Improvement Programs (MNCIP) not May 25, 2016 13.5% 2017 12% 2018 10% 2019 1.7% 40% 2017 35% 2018 30% 2019 Based on results from the 2017 $2.6 2017. 2017 10% 2016 2017 not $2.6 March 31, 2018. Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 March 22, 2018 second 2018. 1935, Environmental Cost Recovery Rider 2010 2016 November 2017. Renewable Resource Adjustment November 1, 2017, 2017 2018. North Dakota General Rates November 2, 2017 $13.1 8.72%. $13.1 7.97% 10.30%. December 20, 2017 $12.8 January 1, 2018. 2018 February 27, 2018 $4.5 $8.3 March 1, 2018. March 23, 2018 $13.1 $7.1 4.8% $6.0 $4.8 $1.2 OTP’s most recently approved general rate increase in North Dakota of $3.6 3.0%, November 25, 2009 December 2009. 8.62%, 10.75%. Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider South Dakota General Rate s April 20, 2018 $3.3 10.1%, first two May 21, 2018 May 15, 2018. second 1.7% January 1, 2020 2019. OTP’s most recently approved general rate increase in South Dakota of approximately $643,000 2.32% April 21, 2011 June 1, 2011. 8.50%. Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three March 31: Rate Rider (in thousands) 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,516 $ 1,966 Transmission Cost Recovery (29 ) 2,170 Environmental Cost Recovery (31 ) 2,824 Renewable Resource Recovery 525 -- North Dakota Renewable Resource Adjustment 1,967 1,770 Transmission Cost Recovery 2,062 2,511 Environmental Cost Recovery 1,821 2,488 South Dakota Transmission Cost Recovery 536 441 Environmental Cost Recovery 520 597 Conservation Improvement Program Costs and Incentives 229 240 Total $ 10,116 $ 15,007 1 Includes MNCIP costs recovered in base rates. Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2016 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2017 Incentive and Cost Recovery R – March 31, 2018 October 1, 2018 $ 10,400 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 1 Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket. TCJA The TCJA reduced the federal corporate income tax rate from 35% 21%. 35% February 15, 2018 not February 1, 2018 December 31, 2017 March 31, 2018 $1.9 $0.8 $0.5 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one MVPs—On December 16, 2010 On November 12, 2013 may 12.38% 9.15%. 15 November 12, 2013 February 11, 2015. December 22, 2015 10.32%, September 28, 2016 10.32%. September 2016 On November 6, 2014 50 January 5, 2015 November 12, 2013 10.82% 10.32% 0.5% September 28, 2016. On February 12, 2015 may 12.38% 8.67%. second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 9.7%. second Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 December 31, 2016, first 15 February June 2017 2016 $2.7 December 31, 2016 $1.6 March 31, 2018. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second second first |
Note 4 - Regulatory Assets and
Note 4 - Regulatory Assets and Liabilities | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Schedule of Regulatory Assets and Liabilities [Text Block] | 4. As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations 980 980 605 25 March 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 110,214 $ 119,304 see below Conservation Improvement Program Costs and Incentives 2 5,313 3,468 8,781 30 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,779 6,779 asset lives Deferred Marked-to-Market Losses 1 3,463 1,989 5,452 33 Big Stone II Unrecovered Project Costs – Minnesota 1 657 1,467 2,124 37 Debt Reacquisition Premiums 1 246 904 1,150 174 Big Stone II Unrecovered Project Costs – South Dakota 1 100 417 517 62 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 374 -- 374 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 322 -- 322 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 196 196 asset lives Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1 -- 166 166 see below North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 133 -- 133 21 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 67 67 21 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 38 -- 38 1 Total Regulatory Assets $ 19,736 $ 125,667 $ 145,403 Regulatory Liabilities: Deferred Income Taxes $ -- $ 148,938 $ 148,938 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 84,223 84,223 asset lives Refundable Fuel Clause Adjustment Revenues 2,414 -- 2,414 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,161 -- 1,161 7 North Dakota Renewable Resource Recovery Rider Accrued Refund 371 -- 371 9 North Dakota Environmental Cost Recovery Rider Accrued Refund 351 -- 351 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 317 -- 317 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 304 -- 304 7 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 68 36 104 21 Other 6 82 88 189 South Dakota Transmission Cost Recovery Rider Accrued Refund 60 -- 60 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 37 -- 37 7 Revenue for Rate Case Expenses Subject to Refund – Minnesota 30 -- 30 1 Total Regulatory Liabilities $ 5,119 $ 233,279 $ 238,398 Net Regulatory Asset/(Liability) Position $ 14,617 $ (107,612 ) $ (92,995 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. All Deferred Marked-to-Market Losses recorded as of March 31, 2018 December 2020. Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 174 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. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota and are currently being recovered beginning with the establishment of interim rates in January 2018. Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers. The Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery are employee benefit-related costs that are required to be capitalized for ratemaking purposes and are recovered over the depreciable lives of the assets to which the related labor costs were applied. The Minnesota Southwest Power Pool Transmission Cost Recovery Tracker relates to costs incurred, in excess of the rate at which the costs are being recovered under current rates, that are subject to future recovery under current rates or through future rate adjustments. North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that have not March 31, 2018. North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had not December 31, 2017. MISO Schedule 26/26A 26/26A Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 24 April 2016. North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that had not December 31, 2017. The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of March 31, 2018. The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2018. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that are recoverable from North Dakota customers as of March 31, 2018. The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2018. The Minnesota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of March 31, 2018. The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2018. The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of March 31, 2018. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24 April 2016. The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2018. The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980 |
Note 5 - Reconciliation of Comm
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Stockholders Equity and Earnings per Share [Text Block] | 5 . Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share Reconciliation of Common Shareholders’ Equity (in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 638 (638 ) -- Common Stock Retirements (292 ) (2,117 ) (2,409 ) Net Income 26,215 26,215 Other Comprehensive Loss (502 ) (502 ) Employee Stock Incentive Plans Expense 1,146 1,146 Common Dividends ($0.335 per share) (13,292 ) (13,292 ) Balance, March 31, 2018 $ 198,133 $ 341,841 $ 174,209 $ (6,133 ) $ 708,050 Shelf Registration s and Common Share Distribution Agreement On May 3, 2018 may May 3, 2021. May 3, 2018, 1,500,000 May 3, 2021. May 11, 2018. May 1, 2018 $75 may Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 March 31, 2018: Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 12,950 Retirements: Shares Withheld for Individual Income Tax Requirements (58,495 ) Common Shares Outstanding, March 31, 2018 39,626,594 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three March 31, 2018 2017. not three March 31: 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,550,874 39,350,802 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 223,162 201,639 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 59,130 57,873 Nonvested Restricted Shares 27,643 27,069 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,873 3,342 Total Dilutive Shares 312,808 289,923 Weighted Average Common Shares Outstanding – Diluted 39,863,682 39,640,725 The effect of dilutive shares on earnings per share for the three March 31, 2018 2017, no $0.01 |
Note 6 - Share-based Payments
Note 6 - Share-based Payments | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | 6 . Share-Based Payments Stock Incentive Awards On February 5, 2018 2014 Award Shares/Units Granted Weighted Average Grant- Date Fair Value per Award Vesting Restricted Stock Units Granted 15,200 $ 41.325 25% per year through February 6, 2022 Stock Performance Awards Granted 54,000 $ 35.73 December 31, 2020 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant. Under the performance share awards the aggregate award for performance at target is 54,000 27,000 3 27,000 January 1, 2018 December 31, 2020, 20 January 1, 2018 20 January 1, 2021. may zero 150% 81,000 no 718, The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of March 31, 2018, $5.9 2.2 Amounts of compensation expense recognized under the Company’s six three March 31, 2018 2017 Three months ended March 31, (in thousands) 2018 2017 Stock Performance Awards Granted to Executive Officers $ 651 $ 649 Restricted Stock Units Granted to Executive Officers 249 264 Restricted Stock Granted to Executive Officers 16 22 Restricted Stock Granted to Directors 166 128 Restricted Stock Units Granted to Non-Executive Employees 64 87 Totals $ 1,146 $ 1,150 |
Note 7 - Retained Earnings and
Note 7 - Retained Earnings and Dividend Restriction | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Retained Earnings Restrictions [Text Block] | 7 . Retained Earnings and Dividend Restriction The Company is a holding company with no Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not March 31, 2018, 9 Under the Federal Power Act, a public utility may not 1 2 not 3 no The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.4% 58.0% 2017 September 1, 2017. March 31, 2018, 51.6% $481,000,000. $1,178,024,000. |
Note 8 - Commitments and Contin
Note 8 - Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | 8 . Commitments and Contingencies Construction and Other Purchase Commitments At March 31, 2018 2019 $37.5 December 31, 2017 2019 $41.0 March 31, 2018 December 31, 2021 $6.2 December 31, 2017 December 31, 2021 $6.7 Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2041. 2019 2040, December 31, 2023. no Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. In the first 2018, April 2018 May 2021, $243,000 2018, $324,000 2019, $324,000 2020 $135,000 2021. Contingencies OTP had a $1.6 March 31, 2018 Together with as many as 200 April 1, 2005 May 2, 2015. not January 26, 2018. May 2, 2018. 2018. not Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as $1.0 In 2014 CO2 CO2 111 October 23, 2015. February 9, 2016 September 27, 2016 first 2017. 13783, or rescinding the CO2 October 16, 2017 Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2018 not |
Note 9 - Short-term and Long-te
Note 9 - Short-term and Long-term Borrowings | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Debt Disclosure [Text Block] | 9 . Short-Term and Long-Term Borrowings The following table presents the status of the Company’s lines of credit as of March 31, 2018 December 31, 2017: (in thousands) Line Limit In Use on March 31, 2018 Restricted due to Outstanding Letters of Credit Available on March 31, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,182 $ -- $ 123,818 $ 130,000 OTP Credit Agreement 170,000 24,137 300 145,563 57,239 Total $ 300,000 $ 30,319 $ 300 $ 269,381 $ 187,239 Debt Issuances 2018 On November 14, 2017, 2018 $100 4.07% 2018A February 7, 2048 ( 2018 2018 February 7, 2018. 2018 OTP may not 10% 100% no August 7, 2047 2018 100% 2018 The 2018 2018 2018 not 2018 not 2018 2018 2018 2018 2018 2018 no The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2018 December 31, 2017: March 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 24,137 $ 6,182 $ 30,319 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, due April 1, 2018 7 7 PACE Note, 2.54%, due March 18, 2021 644 644 Total $ 512,000 $ 80,651 $ 592,651 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 171 171 Unamortized Long-Term Debt Issuance Costs 2,091 446 2,537 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,909 $ 80,034 $ 589,943 Total Short-Term and Long-Term Debt (with current maturities) $ 534,046 $ 86,387 $ 620,433 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937 |
Note 10 - Pension Plan and Othe
Note 10 - Pension Plan and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | 1 0 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 Interest Cost on Projected Benefit Obligation 3,363 3,534 Expected Return on Assets (5,300 ) (4,807 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 30 From Other Comprehensive Income 1 -- 1 Amortization of Net Actuarial Loss: From Regulatory Asset 1,784 1,273 From Other Comprehensive Income 1 44 31 Net Periodic Pension Cost 2 $ 1,510 $ 1,469 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs : C osts included in OTP c apital e xpenditures $ 328 $ 285 Service c osts included in e lectric o peration and m aintenance e xpenses 1,247 1,100 Service c osts included in o ther n onelectric e xpenses 40 34 Nonservice costs capitalized as regulatory assets (21 ) -- Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits (84 ) 50 Cash flows no December 31, 2017 $20 March 31, 2018. Executive Survivor and Supplemental Retirement Plan Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 73 Interest Cost on Projected Benefit Obligation 399 422 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 From Other Comprehensive Income 1 10 9 Amortization of Net Actuarial Loss: From Regulatory Asset 67 71 From Other Comprehensive Income 1 165 110 Net Periodic Pension Cost 2 $ 745 $ 689 1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice c ost c omponents of p ostretirement b enefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs : Service c osts included in e lectric o peration and m aintenance e xpenses $ 25 $ 24 Service costs included in ot her n onelectric e xpenses 75 49 Nonservice c osts included in n onservice c ost c omponents of p ostretirement b enefits 645 616 Postretirement Benefits Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 382 $ 356 Interest Cost on Projected Benefit Obligation 645 678 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 From Other Comprehensive Income 1 10 6 Net Periodic Postretirement Benefit Cost 2 $ 1,449 $ 1,273 Effect of Medicare Part D Subsidy $ (37 ) $ (140 ) 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs : C osts included in OTP c apital e xpenditures $ 78 $ 247 Service c osts included in e lectric operation and maintenance expenses 294 278 Service c osts included in o ther n onelectric e xpenses 10 9 Nonservice costs capitalized as regulatory assets 217 -- Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits 850 739 |
Note 11 - Fair Value of Financi
Note 11 - Fair Value of Financial Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Fair Value Disclosures [Text Block] | 1 1 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt March 31, 2018 December 31, 2017 LIBOR 1.50% 1.25% Long-Term Debt including Current Maturities 2 820. March 31, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,121 $ 1,121 $ 16,216 $ 16,216 Short-Term Debt (30,319 ) (30,319 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,114 ) (614,873 ) (490,566 ) (543,691 ) |
Note 13 - Income Tax Expense -
Note 13 - Income Tax Expense - Continuing Operations | 3 Months Ended |
Mar. 31, 2018 | |
Notes to Financial Statements | |
Income Tax Disclosure [Text Block] | 1 3 . Income Tax Expense – Continuing Operations The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three March 31, 2018 2017: Three Months Ended March 31, (in thousands) 2018 2017 Income Before Income Taxes – Continuing Operations $ 30,009 $ 25,892 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017) 7,802 10,098 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,120 ) (2,052 ) Property Related Differences and Other Regulatory Adjustments (1,073 ) 105 Excess Tax Deduction – Equity Method Stock Awards (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (212 ) Research and Development and Other Tax Credits (180 ) (157 ) Allowance for Funds Used During Construction – Equity (167 ) (67 ) Corporate Owned Life Insurance (8 ) (294 ) Section 199 Domestic Production Activities Deduction -- (330 ) Other Items – Net (47 ) (31 ) Income Tax Expense – Continuing Operations $ 3,794 $ 6,363 Effective Income Tax Rate – Continuing Operations 12.6 % 24.6 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 36 43 Uncertain Positions Resolved During Year -- -- Balance on March 31 $ 676 $ 934 The balance of unrecognized tax benefits as of March 31, 2018 March 31, 2018 not 12 no March 31, 2018. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of May 1, 2018, no 2014 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP currently is recovering costs and earning incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA) and Conservation Improvement Program (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers. Amounts accrued and subject to future recovery, or amounts billed that are subject to refund, through future rider rate updates and adjustments are reported as ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three March 31, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three March 31, 2018 2017. |
Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block] | Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases and carried at historical cost in the accompanying balance sheet. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2018 December 31, 2017: March 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,220 Corporate Debt Securities – Held by Captive Insurance Company $ 5,341 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,779 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 870 Total Assets $ 2,090 $ 7,120 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company third may |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Coyote Station Lignite Supply Agreement – Variable Interest Entity October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 March 31, 2018 $56.5 35% |
Inventory, Policy [Policy Text Block] | Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2018 2017 Finished Goods $ 25,341 $ 26,605 Work in Process 17,224 14,222 Raw Material, Fuel and Supplies 45,434 47,207 Total Inventories $ 87,999 $ 88,034 |
Goodwill and Intangible Assets, Policy [Policy Text Block] | Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first three 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) March 31, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2018 December 31, 2017: March 31 , 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,277 $ 13,214 21 - 209 Covenant not to Compete 590 508 82 5 Other 154 30 124 29 Total $ 23,235 $ 9,815 $ 13,420 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 332 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 |
Cash Flow Supplemental [Policy Text Block] | Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,451 $ 10,811 |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 . 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01are December 15, 2017, 2016 01 first 2018, March 31, 2018 $1,220,000 first 2018 $87,000. ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three March 31, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. ASU 201 8 - 0 2 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $784,000 |
Note 1 - Summary of Significa21
Note 1 - Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | March 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,220 Corporate Debt Securities – Held by Captive Insurance Company $ 5,341 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,779 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 870 Total Assets $ 2,090 $ 7,120 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 |
Schedule of Inventory, Current [Table Text Block] | March 31, December 31, (in thousands) 2018 2017 Finished Goods $ 25,341 $ 26,605 Work in Process 17,224 14,222 Raw Material, Fuel and Supplies 45,434 47,207 Total Inventories $ 87,999 $ 88,034 |
Schedule of Goodwill [Table Text Block] | (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) March 31, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 |
Schedule of Other Intangible Assets [Table Text Block] | March 31 , 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,277 $ 13,214 21 - 209 Covenant not to Compete 590 508 82 5 Other 154 30 124 29 Total $ 23,235 $ 9,815 $ 13,420 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 |
Finite-lived Intangible Assets Amortization Expense [Table Text Block] | Three Months Ended March 31, (in thousands) 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 332 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] | (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | As of March 31, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,451 $ 10,811 |
Note 2 - Segment Information (T
Note 2 - Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended March 31, (in thousands) 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 109,180 $ 106,454 Changes in Accrued ARP Revenues (875 ) (1,239 ) Total Retail Sales Revenue 108,305 105,215 Wholesale Revenues – Company Generation 1,015 867 Other Revenues 13,645 12,469 Total Electric Segment Revenues $ 122,965 $ 118,551 Manufacturing Segment: Metal Parts and Tooling $ 56,927 $ 48,078 Plastic Products 10,235 9,552 Other 1,500 787 Total Manufacturing Segment Revenues $ 68,662 $ 58,417 Plastics Segment – Sale of PVC Pipe Products $ 49,653 $ 37,157 Intersegment Eliminations $ (14 ) $ (8 ) Total $ 241,266 $ 214,117 Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 6,390 $ 6,386 Manufacturing 554 554 Plastics 150 153 Corporate and Intersegment Eliminations 278 369 Total $ 7,372 $ 7,462 Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 2,098 $ 6,062 Manufacturing 1,223 1,055 Plastics 2,414 1,390 Corporate (1,941 ) (2,144 ) Total $ 3,794 $ 6,363 Three Months Ended March 31, (in thousands) 2018 2017 Electric $ 16,668 $ 15,560 Manufacturing 4,164 2,172 Plastics 6,844 2,437 Corporate (1,461 ) (640 ) Discontinued Operations -- 56 Total $ 26,215 $ 19,585 March 31, December 31, (in thousands) 2018 2017 Electric $ 1,686,255 $ 1,690,224 Manufacturing 180,319 167,023 Plastics 97,953 87,230 Corporate 42,891 59,801 Total $ 2,007,418 $ 2,004,278 |
Note 3 - Rate and Regulatory 23
Note 3 - Rate and Regulatory Matters (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Revenues Recorded under Rate Riders [Table Text Block] | Rate Rider (in thousands) 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,516 $ 1,966 Transmission Cost Recovery (29 ) 2,170 Environmental Cost Recovery (31 ) 2,824 Renewable Resource Recovery 525 -- North Dakota Renewable Resource Adjustment 1,967 1,770 Transmission Cost Recovery 2,062 2,511 Environmental Cost Recovery 1,821 2,488 South Dakota Transmission Cost Recovery 536 441 Environmental Cost Recovery 520 597 Conservation Improvement Program Costs and Incentives 229 240 Total $ 10,116 $ 15,007 |
Schedule of Information on Status of Updates for Previous Periods [Table Text Block] | Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2017 Incentive and Cost Recovery R – March 31, 2018 October 1, 2018 $ 10,400 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh |
Note 4 - Regulatory Assets an24
Note 4 - Regulatory Assets and Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | March 31, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 110,214 $ 119,304 see below Conservation Improvement Program Costs and Incentives 2 5,313 3,468 8,781 30 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,779 6,779 asset lives Deferred Marked-to-Market Losses 1 3,463 1,989 5,452 33 Big Stone II Unrecovered Project Costs – Minnesota 1 657 1,467 2,124 37 Debt Reacquisition Premiums 1 246 904 1,150 174 Big Stone II Unrecovered Project Costs – South Dakota 1 100 417 517 62 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 374 -- 374 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 322 -- 322 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 196 196 asset lives Minnesota Southwest Power Pool Transmission Cost Recovery Tracker 1 -- 166 166 see below North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 133 -- 133 21 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 67 67 21 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 38 -- 38 1 Total Regulatory Assets $ 19,736 $ 125,667 $ 145,403 Regulatory Liabilities: Deferred Income Taxes $ -- $ 148,938 $ 148,938 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 84,223 84,223 asset lives Refundable Fuel Clause Adjustment Revenues 2,414 -- 2,414 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,161 -- 1,161 7 North Dakota Renewable Resource Recovery Rider Accrued Refund 371 -- 371 9 North Dakota Environmental Cost Recovery Rider Accrued Refund 351 -- 351 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 317 -- 317 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 304 -- 304 7 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 68 36 104 21 Other 6 82 88 189 South Dakota Transmission Cost Recovery Rider Accrued Refund 60 -- 60 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 37 -- 37 7 Revenue for Rate Case Expenses Subject to Refund – Minnesota 30 -- 30 1 Total Regulatory Liabilities $ 5,119 $ 233,279 $ 238,398 Net Regulatory Asset/(Liability) Position $ 14,617 $ (107,612 ) $ (92,995 ) December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 ) |
Note 5 - Reconciliation of Co25
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Stockholders Equity [Table Text Block] | (in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 638 (638 ) -- Common Stock Retirements (292 ) (2,117 ) (2,409 ) Net Income 26,215 26,215 Other Comprehensive Loss (502 ) (502 ) Employee Stock Incentive Plans Expense 1,146 1,146 Common Dividends ($0.335 per share) (13,292 ) (13,292 ) Balance, March 31, 2018 $ 198,133 $ 341,841 $ 174,209 $ (6,133 ) $ 708,050 |
Schedule of Common Stock Outstanding Roll Forward [Table Text Block] | Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 12,950 Retirements: Shares Withheld for Individual Income Tax Requirements (58,495 ) Common Shares Outstanding, March 31, 2018 39,626,594 |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,550,874 39,350,802 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 223,162 201,639 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 59,130 57,873 Nonvested Restricted Shares 27,643 27,069 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,873 3,342 Total Dilutive Shares 312,808 289,923 Weighted Average Common Shares Outstanding – Diluted 39,863,682 39,640,725 |
Note 6 - Share-based Payments (
Note 6 - Share-based Payments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block] | Award Shares/Units Granted Weighted Average Grant- Date Fair Value per Award Vesting Restricted Stock Units Granted 15,200 $ 41.325 25% per year through February 6, 2022 Stock Performance Awards Granted 54,000 $ 35.73 December 31, 2020 |
Share-based Compensation, Activity [Table Text Block] | Three months ended March 31, (in thousands) 2018 2017 Stock Performance Awards Granted to Executive Officers $ 651 $ 649 Restricted Stock Units Granted to Executive Officers 249 264 Restricted Stock Granted to Executive Officers 16 22 Restricted Stock Granted to Directors 166 128 Restricted Stock Units Granted to Non-Executive Employees 64 87 Totals $ 1,146 $ 1,150 |
Note 9 - Short-term and Long-27
Note 9 - Short-term and Long-term Borrowings (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Line of Credit Facilities [Table Text Block] | (in thousands) Line Limit In Use on March 31, 2018 Restricted due to Outstanding Letters of Credit Available on March 31, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,182 $ -- $ 123,818 $ 130,000 OTP Credit Agreement 170,000 24,137 300 145,563 57,239 Total $ 300,000 $ 30,319 $ 300 $ 269,381 $ 187,239 |
Schedule of Debt [Table Text Block] | March 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 24,137 $ 6,182 $ 30,319 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, due April 1, 2018 7 7 PACE Note, 2.54%, due March 18, 2021 644 644 Total $ 512,000 $ 80,651 $ 592,651 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 171 171 Unamortized Long-Term Debt Issuance Costs 2,091 446 2,537 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,909 $ 80,034 $ 589,943 Total Short-Term and Long-Term Debt (with current maturities) $ 534,046 $ 86,387 $ 620,433 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937 |
Note 10 - Pension Plan and Ot28
Note 10 - Pension Plan and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Net Benefit Costs [Table Text Block] | Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 Interest Cost on Projected Benefit Obligation 3,363 3,534 Expected Return on Assets (5,300 ) (4,807 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 30 From Other Comprehensive Income 1 -- 1 Amortization of Net Actuarial Loss: From Regulatory Asset 1,784 1,273 From Other Comprehensive Income 1 44 31 Net Periodic Pension Cost 2 $ 1,510 $ 1,469 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs : C osts included in OTP c apital e xpenditures $ 328 $ 285 Service c osts included in e lectric o peration and m aintenance e xpenses 1,247 1,100 Service c osts included in o ther n onelectric e xpenses 40 34 Nonservice costs capitalized as regulatory assets (21 ) -- Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits (84 ) 50 Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 73 Interest Cost on Projected Benefit Obligation 399 422 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 From Other Comprehensive Income 1 10 9 Amortization of Net Actuarial Loss: From Regulatory Asset 67 71 From Other Comprehensive Income 1 165 110 Net Periodic Pension Cost 2 $ 745 $ 689 1 Amortization of p rior s ervice c osts and net actuarial losses from o ther c omprehensive i ncome are included in n onservice c ost c omponents of p ostretirement b enefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs : Service c osts included in e lectric o peration and m aintenance e xpenses $ 25 $ 24 Service costs included in ot her n onelectric e xpenses 75 49 Nonservice c osts included in n onservice c ost c omponents of p ostretirement b enefits 645 616 Three Months Ended March 31, (in thousands) 2018 2017 Service Cost—Benefit Earned During the Period $ 382 $ 356 Interest Cost on Projected Benefit Obligation 645 678 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 From Other Comprehensive Income 1 10 6 Net Periodic Postretirement Benefit Cost 2 $ 1,449 $ 1,273 Effect of Medicare Part D Subsidy $ (37 ) $ (140 ) 1 Corporate cost included in n onservice c ost c omponents of p ostretirement b enefits . 2 Allocation of Costs : C osts included in OTP c apital e xpenditures $ 78 $ 247 Service c osts included in e lectric operation and maintenance expenses 294 278 Service c osts included in o ther n onelectric e xpenses 10 9 Nonservice costs capitalized as regulatory assets 217 -- Nonservice costs included in n onservice c ost c omponents of p ostretirement b enefits 850 739 |
Note 11 - Fair Value of Finan29
Note 11 - Fair Value of Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Fair Value, by Balance Sheet Grouping [Table Text Block] | March 31, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,121 $ 1,121 $ 16,216 $ 16,216 Short-Term Debt (30,319 ) (30,319 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,114 ) (614,873 ) (490,566 ) (543,691 ) |
Note 13 - Income Tax Expense 30
Note 13 - Income Tax Expense - Continuing Operations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Notes Tables | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Three Months Ended March 31, (in thousands) 2018 2017 Income Before Income Taxes – Continuing Operations $ 30,009 $ 25,892 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017) 7,802 10,098 Increases (Decreases) in Tax from: Federal Production Tax Credits (1,120 ) (2,052 ) Property Related Differences and Other Regulatory Adjustments (1,073 ) 105 Excess Tax Deduction – Equity Method Stock Awards (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (212 ) Research and Development and Other Tax Credits (180 ) (157 ) Allowance for Funds Used During Construction – Equity (167 ) (67 ) Corporate Owned Life Insurance (8 ) (294 ) Section 199 Domestic Production Activities Deduction -- (330 ) Other Items – Net (47 ) (31 ) Income Tax Expense – Continuing Operations $ 3,794 $ 6,363 Effective Income Tax Rate – Continuing Operations 12.6 % 24.6 % |
Summary of Income Tax Contingencies [Table Text Block] | (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 36 43 Uncertain Positions Resolved During Year -- -- Balance on March 31 $ 676 $ 934 |
Note 1 - Summary of Significa31
Note 1 - Summary of Significant Accounting Policies (Details Textual) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Goodwill, Period Increase (Decrease), Total | $ 0 | |||
Pro Forma [Member] | Accounting Standards Update 2017-07 [Member] | ||||
Postretirement Benefit Plan, Nonservice Costs Capitalized to Plant in Service During Fiscal Year | $ 800,000 | |||
Postretirement Benefit Plan, Nonservice Costs Included in Operating Expense During Fiscal Year | $ 5,600,000 | $ 5,100,000 | ||
Scenario, Forecast [Member] | Accounting Standards Update 2018-02 [Member] | ||||
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect | $ 784,000 | |||
Equity Instruments Held by the Company's Captive Insurance Company [Member] | ||||
Equity Securities, FV-NI | 1,220,000 | |||
Equity Securities, FV-NI, Unrealized Gain | 87,000 | |||
Coyote Creek Mining Company, L.L.C. (CCMC) [Member] | Otter Tail Power Company [Member] | Lignite Sales Agreement [Member] | ||||
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount | $ 56,500,000 | |||
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage | 35.00% | |||
Plastics [Member] | ||||
Number of Customers Under Build and Hold Agreements | 1 | |||
Goodwill, Period Increase (Decrease), Total |
Note 1 - Summary of Significa32
Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Total Assets | $ 2,090 | $ 2,108 |
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | ||
Assets: | ||
Investments | 1,220 | 1,285 |
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member] | ||
Assets: | ||
Investments | ||
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Assets: | ||
Investments | ||
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member] | ||
Assets: | ||
Other Assets | 870 | 823 |
Fair Value, Inputs, Level 2 [Member] | ||
Assets: | ||
Total Assets | 7,120 | 7,160 |
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member] | ||
Assets: | ||
Investments | ||
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | ||
Assets: | ||
Investments | 5,341 | 5,373 |
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Assets: | ||
Investments | 1,779 | 1,787 |
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member] | ||
Assets: | ||
Other Assets |
Note 1 - Summary of Significa33
Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Finished Goods | $ 25,341 | $ 26,605 |
Work in Process | 17,224 | 14,222 |
Raw Material, Fuel and Supplies | 45,434 | 47,207 |
Total Inventories | $ 87,999 | $ 88,034 |
Note 1 - Summary of Significa34
Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Gross Balance | $ 37,572,000 | |
Accumulated Impairments | ||
Balance | $ 37,572,000 | 37,572,000 |
Adjustments to Goodwill | 0 | |
Manufacturing [Member] | ||
Gross Balance | 18,270,000 | |
Accumulated Impairments | ||
Balance | 18,270,000 | 18,270,000 |
Adjustments to Goodwill | ||
Plastics [Member] | ||
Gross Balance | 19,302,000 | |
Accumulated Impairments | ||
Balance | 19,302,000 | $ 19,302,000 |
Adjustments to Goodwill |
Note 1 - Summary of Significa35
Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 23,235 | $ 23,235 |
Accumulated Amortization | 9,815 | 9,470 |
Net Carrying Amount | 13,420 | 13,765 |
Customer Relationships [Member] | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 22,491 | 22,491 |
Accumulated Amortization | 9,277 | 8,994 |
Net Carrying Amount | $ 13,214 | $ 13,497 |
Customer Relationships [Member] | Minimum [Member] | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods (Month) | 1 year 270 days | 2 years |
Customer Relationships [Member] | Maximum [Member] | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods (Month) | 17 years 150 days | 17 years 240 days |
Covenant Not to Compete [Member] | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 590 | $ 590 |
Accumulated Amortization | 508 | 459 |
Net Carrying Amount | $ 82 | $ 131 |
Remaining Amortization Periods (Month) | 150 days | 240 days |
Other Intangible Assets [Member] | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 154 | $ 154 |
Accumulated Amortization | 30 | 17 |
Net Carrying Amount | $ 124 | $ 137 |
Remaining Amortization Periods (Month) | 2 years 150 days | 2 years 240 days |
Note 1 - Summary of Significa36
Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Amortization Expense – Intangible Assets | $ 345 | $ 332 |
Note 1 - Summary of Significa37
Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands | Mar. 31, 2018USD ($) |
2,018 | $ 1,315 |
2,019 | 1,184 |
2,020 | 1,133 |
2,021 | 1,099 |
2,022 | $ 1,099 |
Note 1 - Summary of Significa38
Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Mar. 31, 2017 |
Transactions Related to Capital Additions not Settled in Cash | $ 10,451 | $ 10,811 |
Note 2 - Segment Information (D
Note 2 - Segment Information (Details Textual) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Number of Reportable Segments | 3 | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Electric [Member] | |||
Number of Customers | 1 | ||
Concentration Risk, Percentage | 11.70% | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member] | |||
Number of Customers | 1 | ||
Concentration Risk, Percentage | 24.30% | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member] | |||
Number of Customers | 1 | ||
Concentration Risk, Percentage | 12.00% | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | |||
Number of Customers | 2 | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer One [Member] | |||
Concentration Risk, Percentage | 20.60% | ||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer Two [Member] | |||
Concentration Risk, Percentage | 17.80% | ||
Sales Revenue, Net [Member] | UNITED STATES | |||
Concentration Risk, Percentage | 98.30% | 98.40% |
Note 2 - Segment Information -
Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Electric Sales | $ 241,266 | $ 214,117 | |
Interest charges | 7,372 | 7,462 | |
Income Taxes | 3,794 | 6,363 | |
Net Income (Loss) | 26,215 | 19,585 | |
Assets | 2,007,418 | $ 2,004,278 | |
Discontinued Operations [Member] | |||
Net Income (Loss) | 56 | ||
Operating Segments [Member] | Electric [Member] | |||
Revenue from Contracts with Customers | 13,645 | 12,469 | |
Regulated operating revenues | 122,965 | 118,551 | |
Interest charges | 6,390 | 6,386 | |
Income Taxes | 2,098 | 6,062 | |
Net Income (Loss) | 16,668 | 15,560 | |
Assets | 1,686,255 | 1,690,224 | |
Operating Segments [Member] | Electric [Member] | Retail [Member] | |||
Revenue from Contracts with Customers | 109,180 | 106,454 | |
Changes in Accrued ARP Revenues | (875) | (1,239) | |
Regulated operating revenues | 108,305 | 105,215 | |
Operating Segments [Member] | Electric [Member] | Wholesale [Member] | |||
Revenue from Contracts with Customers | 1,015 | 867 | |
Operating Segments [Member] | Manufacturing [Member] | |||
Revenue from Contracts with Customers | 68,662 | 58,417 | |
Interest charges | 554 | 554 | |
Income Taxes | 1,223 | 1,055 | |
Net Income (Loss) | 4,164 | 2,172 | |
Assets | 180,319 | 167,023 | |
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member] | |||
Revenue from Contracts with Customers | 56,927 | 48,078 | |
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member] | |||
Revenue from Contracts with Customers | 10,235 | 9,552 | |
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member] | |||
Revenue from Contracts with Customers | 1,500 | 787 | |
Operating Segments [Member] | Plastics [Member] | |||
Revenue from Contracts with Customers | 49,653 | 37,157 | |
Interest charges | 150 | 153 | |
Income Taxes | 2,414 | 1,390 | |
Net Income (Loss) | 6,844 | 2,437 | |
Assets | 97,953 | 87,230 | |
Corporate and Eliminations [Member] | |||
Interest charges | 278 | 369 | |
Income Taxes | (1,941) | (2,144) | |
Net Income (Loss) | (1,461) | (640) | |
Assets | 42,891 | $ 59,801 | |
Intersegment Eliminations [Member] | |||
Regulated operating revenues | $ (14) | $ (8) |
Note 3 - Rate and Regulatory 41
Note 3 - Rate and Regulatory Matters (Details Textual) | Apr. 20, 2018USD ($) | Mar. 23, 2018USD ($) | Mar. 22, 2018USD ($) | Dec. 20, 2017USD ($) | Nov. 17, 2017USD ($) | Sep. 28, 2016 | May 25, 2016 | Feb. 12, 2015 | Nov. 06, 2014 | Nov. 12, 2013 | Jun. 01, 2011USD ($) | Jun. 30, 2016 | Dec. 22, 2015 | Mar. 31, 2018USD ($) | Dec. 31, 2018 | Dec. 31, 2017USD ($) | Mar. 01, 2018USD ($) | Nov. 02, 2017USD ($) | Oct. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Apr. 16, 2016 | Apr. 15, 2016 | Nov. 25, 2009USD ($) |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | ||||||||||||||||||||||
Regulatory Liabilities, Total | $ 238,398,000 | $ 242,581,000 | |||||||||||||||||||||
Minnesota [Member] | |||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 1,900,000 | ||||||||||||||||||||||
NORTH DAKOTA | |||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 800,000 | ||||||||||||||||||||||
South Dakota [Member] | |||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 500,000 | ||||||||||||||||||||||
Scenario, Forecast [Member] | |||||||||||||||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||
Current Return on Equity Used in Transmission Rates | 10.32% | 12.38% | 10.32% | ||||||||||||||||||||
Proposed Reduced Return on Equity Used in Transmission Rates | 8.67% | 9.15% | 9.70% | ||||||||||||||||||||
Additional Incentive Basis Point | 0.50% | ||||||||||||||||||||||
Expected Percentage of Return on Equity | 10.82% | ||||||||||||||||||||||
Regulatory Liabilities, Total | $ 1,600,000 | $ 2,700,000 | |||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||
Estimated Interim Rate Refund | $ 9,000,000 | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 7.5056% | 8.61% | |||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 9.41% | 10.74% | |||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Environmental Cost Recovery Rider [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Customer Refund | $ 900,000 | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Customer Refund | $ 1,400,000 | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | ECR and TCR Riders [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Refund, Period of Refund | 1 year | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | |||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Twelve Months | 13.50% | ||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Year Two | 12.00% | ||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Year Three | 10.00% | ||||||||||||||||||||||
Assumed Savings of Utility | 1.70% | ||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year One | 40.00% | ||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year Two | 35.00% | ||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year Three | 30.00% | ||||||||||||||||||||||
Financial Incentives Recognized During Period | $ 2,600,000 | ||||||||||||||||||||||
Percentage Decrease in Energy Savings | 10.00% | ||||||||||||||||||||||
Amount Of Financial Incentive Requested | $ 2,600,000 | ||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2010 General Rate Case [Member] | |||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 7.97% | 8.62% | |||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.30% | 10.75% | |||||||||||||||||||||
General Rate Revenue Increase Requested | $ 13,100,000 | $ 3,600,000 | |||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Requested | 8.72% | 3.00% | |||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 12,800,000 | ||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Decrease in Amount | $ 4,500,000 | ||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Amount | $ 8,300,000 | ||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7,100,000 | $ 13,100,000 | |||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.80% | ||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease | $ 6,000,000 | ||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform | 4,800,000 | ||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform | $ 1,200,000 | ||||||||||||||||||||||
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member] | |||||||||||||||||||||||
Public Utilities General Rate Revenue Increase Approved | $ 643,000 | ||||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Approved | 2.32% | ||||||||||||||||||||||
Public Utilities Allowed Rate of Return on Rate Base Subsequent to Approval of Increase in Base Rate | 8.50% | ||||||||||||||||||||||
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member] | Subsequent Event [Member] | |||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 3,300,000 | ||||||||||||||||||||||
Increase in Annual Non-fuel Rates Requested, Step One, Percentage | 10.10% | ||||||||||||||||||||||
Increase in Annual Non-fuel Rates Requested, Step Two, Percentage | 1.70% | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||
Expanded Capacity of Projects | 345 | ||||||||||||||||||||||
Extended Distance of Transmission Line | 163 | ||||||||||||||||||||||
Current Projected Cost | $ 96,500,000 | ||||||||||||||||||||||
Percentage of Assets of Project | 100.00% | ||||||||||||||||||||||
Otter Tail Power Company [Member] | Big Stone South - Brookings MVP [Member] | |||||||||||||||||||||||
Expanded Capacity of Projects | 345 | ||||||||||||||||||||||
Extended Distance of Transmission Line | 70 | ||||||||||||||||||||||
Current Projected Cost | $ 72,400,000 | ||||||||||||||||||||||
Percentage of Assets of Project | 100.00% |
Note 3 - Rate and Regulatory 42
Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | ||
Revenues recorded under rate riders | $ 10,116 | $ 15,007 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||
Revenues recorded under rate riders | [1] | 2,516 | 1,966 |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 2,170 | ||
Revenues recorded under rate riders | (29) | ||
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 2,824 | ||
Revenues recorded under rate riders | (31) | ||
Minnesota [Member] | Renewable Resource Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 525 | ||
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 2,062 | 2,511 | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 1,821 | 2,488 | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | |||
Revenues recorded under rate riders | 1,967 | 1,770 | |
South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||
Revenues recorded under rate riders | 229 | 240 | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | 536 | 441 | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | |||
Revenues recorded under rate riders | $ 520 | $ 597 | |
[1] | Includes MNCIP costs recovered in base rates. |
Note 3 - Rate and Regulatory 43
Note 3 - Rate and Regulatory Matters - Summary of Status of Updates for Previous Two Years for Various Rate Riders (Details) - Otter Tail Power Company [Member] $ in Thousands | 3 Months Ended | |
Mar. 31, 2018USD ($)kWh | ||
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member] | ||
R - Request Date | Mar. 31, 2018 | |
Effective Date Requested or Approved | Oct. 1, 2018 | |
Annual Revenue | $ 10,400 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.006 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member] | ||
Effective Date Requested or Approved | Oct. 1, 2017 | |
Annual Revenue | $ 9,868 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | |
A - Approval Date | Sep. 15, 2017 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2015 Incentive and Cost Recovery [Member] | ||
Effective Date Requested or Approved | Oct. 1, 2016 | |
Annual Revenue | $ 8,590 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00275 | |
A - Approval Date | Jul. 19, 2016 | |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | [1] |
Annual Revenue | $ (3,311) | [1] |
A - Approval Date | Oct. 30, 2017 | [1] |
Rate | Various | [1] |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Sep. 1, 2016 | |
Annual Revenue | $ 4,736 | |
A - Approval Date | Jul. 5, 2016 | |
Rate | Various | |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Apr. 1, 2016 | |
Annual Revenue | $ 7,203 | |
A - Approval Date | Mar. 9, 2016 | |
Rate | Various | |
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ (1,943) | |
A - Approval Date | Oct. 30, 2017 | |
Rate of base | (0.935%) | |
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Sep. 1, 2016 | |
Annual Revenue | $ 11,884 | |
A - Approval Date | Jul. 5, 2016 | |
Rate of base | 6.927% | |
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ 1,279 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00049 | |
A - Approval Date | Oct. 30, 2017 | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2017 | |
Annual Revenue | $ 6,916 | |
A - Approval Date | Dec. 14, 2016 | |
Rate | Various | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 7,469 | |
A - Approval Date | Feb. 27, 2018 | |
Rate | Various | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 7,959 | |
A - Approval Date | Nov. 29, 2017 | |
Rate | Various | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 8,537 | |
A - Approval Date | Dec. 20, 2017 | |
Rate of base | 6.629% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Jul. 1, 2016 | |
Annual Revenue | $ 10,359 | |
A - Approval Date | Jun. 22, 2016 | |
Rate of base | 7.904% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 7,718 | |
A - Approval Date | Feb. 27, 2018 | |
Rate of base | 5.593% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Aug. 1, 2017 | |
Annual Revenue | $ 9,917 | |
A - Approval Date | Jul. 12, 2017 | |
Rate of base | 7.633% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 9,989 | |
A - Approval Date | Dec. 20, 2017 | |
Rate of base | 7.756% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Apr. 1, 2017 | |
Annual Revenue | $ 9,156 | |
A - Approval Date | Mar. 15, 2017 | |
Rate of base | 7.005% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Jul. 1, 2016 | |
Annual Revenue | $ 9,262 | |
A - Approval Date | Jun. 22, 2016 | |
Rate of base | 7.573% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 9,650 | |
A - Approval Date | Feb. 27, 2018 | |
Rate of base | 7.493% | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2017 | |
Annual Revenue | $ 2,053 | |
A - Approval Date | Feb. 17, 2017 | |
Rate | Various | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2016 | |
Annual Revenue | $ 1,895 | |
A - Approval Date | Feb. 12, 2016 | |
Rate | Various | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 1,779 | |
A - Approval Date | Feb. 28, 2018 | |
Rate | Various | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2016 | |
Annual Revenue | $ 2,238 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | |
A - Approval Date | Oct. 26, 2016 | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ 2,082 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00483 | |
A - Approval Date | Oct. 13, 2017 | |
[1] | Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket. |
Note 4 - Regulatory Assets an44
Note 4 - Regulatory Assets and Liabilities (Details Textual) | 3 Months Ended |
Mar. 31, 2018 | |
Regulatory Noncurrent Asset, Remaining Recovery Period | 14 years 180 days |
Note 4 - Regulatory Assets an45
Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | ||
Regulatory Assets - Current | $ 19,736 | $ 22,551 | |
Regulatory Assets - Long -Term | 125,667 | 129,576 | |
Regulatory Assets - Total | $ 145,403 | $ 152,127 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | |||
Regulatory Liabilities - Current | $ 5,119 | $ 9,688 | |
Regulatory Liabilities - Long -Term | 233,279 | 232,893 | |
Regulatory Liabilities, Total | $ 238,398 | $ 242,581 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | |||
Net Regulatory Asset Position - Current | $ 14,617 | $ 12,863 | |
Net Regulatory Asset Position - Long-Term | (107,612) | (103,317) | |
Net Regulatory Asset/(Liability) Position | (92,995) | (90,454) | |
Deferred Income Taxes [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 148,938 | 149,052 | |
Regulatory Liabilities, Total | $ 148,938 | $ 149,052 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 84,223 | 83,100 | |
Regulatory Liabilities, Total | $ 84,223 | $ 83,100 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Refundable Fuel Clause Adjustment Revenues [Member] | |||
Regulatory Liabilities - Current | $ 2,414 | $ 5,778 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 2,414 | $ 5,778 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 1,161 | $ 1,667 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 1,161 | $ 1,667 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 210 days | 330 days | |
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 317 | $ 187 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 317 | $ 187 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
North Dakota Renewable Resource Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 371 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 371 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 270 days | ||
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 304 | $ 409 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 304 | $ 409 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 210 days | 1 year | |
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 351 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 351 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | ||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Liabilities - Current | $ 68 | $ 132 | |
Regulatory Liabilities - Long -Term | 36 | 48 | |
Regulatory Liabilities, Total | $ 104 | $ 180 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year 270 days | 2 years | |
Other [Member] | |||
Regulatory Liabilities - Current | $ 6 | $ 5 | |
Regulatory Liabilities - Long -Term | 82 | 84 | |
Regulatory Liabilities, Total | $ 88 | $ 89 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 15 years 270 days | 16 years | |
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 60 | $ 151 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 60 | $ 151 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
Minnesota Transmission Cost Recovery Rider Accrued Refund [member] | |||
Regulatory Liabilities - Current | $ 37 | $ 802 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 37 | $ 802 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 210 days | 300 days | |
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 30 | $ 208 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 30 | $ 208 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 30 days | 120 days | |
Minnesota Southwest Power Pool Transmission Cost Tracker Refund [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 609 | ||
Regulatory Liabilities, Total | $ 609 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year 300 days | ||
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 349 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities, Total | $ 349 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | ||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member] | |||
Regulatory Assets - Current | [1] | $ 9,090 | $ 9,090 |
Regulatory Assets - Long -Term | [1] | 110,214 | 112,487 |
Regulatory Assets - Total | [1] | $ 119,304 | $ 121,577 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
Conservation Improvement Program Costs and Incentives [Member] | |||
Regulatory Assets - Current | [2] | $ 5,313 | $ 7,385 |
Regulatory Assets - Long -Term | [2] | 3,468 | 2,774 |
Regulatory Assets - Total | [2] | $ 8,781 | $ 10,159 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 2 years 180 days | 1 year 270 days |
Accumulated ARO Accretion/Depreciation Adjustment [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 6,779 | 6,651 |
Regulatory Assets - Total | [1] | $ 6,779 | $ 6,651 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Deferred Marked-to-Market Losses [Member] | |||
Regulatory Assets - Current | [1] | $ 3,463 | $ 4,063 |
Regulatory Assets - Long -Term | [1] | 1,989 | 2,405 |
Regulatory Assets - Total | [1] | $ 5,452 | $ 6,468 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 2 years 270 days | 3 years |
Big Stone II Unrecovered Project Costs - Minnesota [Member] | |||
Regulatory Assets - Current | [1] | $ 657 | $ 650 |
Regulatory Assets - Long -Term | [1] | 1,467 | 1,636 |
Regulatory Assets - Total | [1] | $ 2,124 | $ 2,286 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 3 years 30 days | 3 years 120 days |
Debt Reacquisition Premiums [Member] | |||
Regulatory Assets - Current | [1] | $ 246 | $ 254 |
Regulatory Assets - Long -Term | [1] | 904 | 960 |
Regulatory Assets - Total | [1] | $ 1,150 | $ 1,214 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 14 years 180 days | 14 years 270 days |
Big Stone II Unrecovered Project Costs - South Dakota [Member] | |||
Regulatory Assets - Current | [1] | $ 100 | $ 100 |
Regulatory Assets - Long -Term | [1] | 417 | 442 |
Regulatory Assets - Total | [1] | $ 517 | $ 542 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 5 years 60 days | 5 years 150 days |
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 374 | $ 309 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 374 | $ 309 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year | 1 year |
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [1] | $ 322 | $ 75 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 322 | $ 75 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year | 1 year |
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 196 | |
Regulatory Assets - Total | [1] | $ 196 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | |
North Dakota Renewable Resource Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 206 | |
Regulatory Assets - Long -Term | [2] | 236 | |
Regulatory Assets - Total | [2] | $ 442 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year 90 days | |
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 166 | |
Regulatory Assets - Total | [1] | $ 166 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 67 | 1,985 |
Regulatory Assets - Total | [1] | $ 67 | $ 1,985 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year 270 days | 2 years |
North Dakota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 133 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 133 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year 270 days | |
Minnesota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 38 | $ 267 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 38 | $ 267 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 30 days | 120 days |
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 152 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 152 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year | |
[1] | Costs subject to recovery excluding a rate of return. | ||
[2] | Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Note 5 - Reconciliation of Co46
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | |||
Mar. 31, 2018 | Mar. 31, 2017 | May 03, 2018 | Apr. 30, 2018 | |
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations | $ 0.01 | $ 0.01 | ||
Dividend Reinvestment and Share Purchase Plan [Member] | Subsequent Event [Member] | ||||
Shelf Registration, Shares | 1,500,000 | |||
Distribution Agreement [Member] | Subsequent Event [Member] | ||||
Agreement to Sell Shares, Value | $ 75 |
Note 5 - Reconciliation of Co47
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Balance, beginning | $ 696,892 | |
Common Stock Issuances, Net of Expenses | ||
Common Stock Retirements | (2,409) | |
Net Income | 26,215 | $ 19,585 |
Other Comprehensive Loss | (502) | |
Employee Stock Incentive Plans Expense | 1,146 | |
Common Dividends ($0.335 per share) | (13,292) | |
Balance, ending | 708,050 | |
Par Value, Common Shares [Member] | ||
Balance, beginning | 197,787 | |
Common Stock Issuances, Net of Expenses | 638 | |
Common Stock Retirements | (292) | |
Net Income | ||
Other Comprehensive Loss | ||
Employee Stock Incentive Plans Expense | ||
Common Dividends ($0.335 per share) | ||
Balance, ending | 198,133 | |
Premium on Common Shares [Member] | ||
Balance, beginning | 343,450 | |
Common Stock Issuances, Net of Expenses | (638) | |
Common Stock Retirements | (2,117) | |
Net Income | ||
Other Comprehensive Loss | ||
Employee Stock Incentive Plans Expense | 1,146 | |
Common Dividends ($0.335 per share) | ||
Balance, ending | 341,841 | |
Retained Earnings [Member] | ||
Balance, beginning | 161,286 | |
Common Stock Issuances, Net of Expenses | ||
Common Stock Retirements | ||
Net Income | 26,215 | |
Other Comprehensive Loss | ||
Employee Stock Incentive Plans Expense | ||
Common Dividends ($0.335 per share) | (13,292) | |
Balance, ending | 174,209 | |
Accumulated Other Comprehensive Income/(Loss) [Member] | ||
Balance, beginning | (5,631) | |
Common Stock Issuances, Net of Expenses | ||
Common Stock Retirements | ||
Net Income | ||
Other Comprehensive Loss | (502) | |
Employee Stock Incentive Plans Expense | ||
Common Dividends ($0.335 per share) | ||
Balance, ending | $ (6,133) |
Note 5 - Reconciliation of Co48
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) (Parentheticals) - $ / shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Dividends Declared Per Common Share (in dollars per share) | $ 0.335 | $ 0.32 |
Note 5 - Reconciliation of Co49
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details) | 3 Months Ended |
Mar. 31, 2018shares | |
Common Shares Outstanding, beginning balance (in shares) | 39,557,491 |
Issuances: | |
Executive Stock Performance Awards (2015 shares earned) (in shares) | 114,648 |
Vesting of Restricted Stock Units (in shares) | 12,950 |
Retirements: | |
Shares Withheld for Individual Income Tax Requirements (in shares) | (58,495) |
Common Shares Outstanding, ending balance (in shares) | 39,626,594 |
Note 5 - Reconciliation of Co50
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Weighted Average Common Shares Outstanding – Basic (in shares) | 39,550,874 | 39,350,802 |
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: | ||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares) | 223,162 | 201,639 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares) | 59,130 | 57,873 |
Nonvested Restricted Shares (in shares) | 27,643 | 27,069 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares) | 2,873 | 3,342 |
Total Dilutive Shares (in shares) | 312,808 | 289,923 |
Weighted Average Common Shares Outstanding – Diluted (in shares) | 39,863,682 | 39,640,725 |
Note 6 - Share-based Payments51
Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions | Feb. 05, 2018 | Mar. 31, 2018 |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Total | $ 5.9 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years 73 days | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 54,000 | |
Period Specified for Average Adjusted Return | 3 years | |
Number of Trading Days | 20 days | |
Number of Shares Authorized for Actual Payment | 81,000 | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member] | ||
Percentage of Target Amount as Actual Payment | 0.00% | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member] | ||
Percentage of Target Amount as Actual Payment | 150.00% | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,000 | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,000 |
Note 6 - Share-based Payments -
Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) - Executive Officer [Member] - The 2014 Stock Incentive Plan [Member] | Feb. 05, 2018$ / sharesshares |
Restricted Stock Units (RSUs) [Member] | |
Shares/units granted (in shares) | shares | 15,200 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 41.325 |
Shares/units granted, vesting date | Feb. 6, 2022 |
Stock Performance Awards [Member] | |
Shares/units granted (in shares) | shares | 54,000 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 35.73 |
Shares/units granted, vesting date | Dec. 31, 2020 |
Note 6 - Share-based Payments53
Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals) | Feb. 05, 2018 |
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | Executive Officer [Member] | |
Shares/units granted, vesting percentage | 25.00% |
Note 6 - Share-based Payments54
Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Stock compensation expense | $ 1,146 | $ 1,150 |
Stock Performance Awards [Member] | Executive Officer [Member] | ||
Stock compensation expense | 651 | 649 |
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | ||
Stock compensation expense | 249 | 264 |
Restricted Stock Units (RSUs) [Member] | Non-executive Employees [Member] | ||
Stock compensation expense | 64 | 87 |
Restricted Stock [Member] | Executive Officer [Member] | ||
Stock compensation expense | 16 | 22 |
Restricted Stock [Member] | Directors [Member] | ||
Stock compensation expense | $ 166 | $ 128 |
Note 7 - Retained Earnings an55
Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Capitalization, Long-term Debt and Equity, Total | $ 1,297,993,000 | $ 1,187,272,000 |
Otter Tail Power Company [Member] | ||
Equity to Total Capitalization Ratio | 51.60% | |
Net Assets Restricted from Distribution | $ 481,000,000 | |
Capitalization, Long-term Debt and Equity, Total | $ 1,178,024,000 | |
Otter Tail Power Company [Member] | Minimum [Member] | ||
Equity to Total Capitalization Ratio | 47.40% | |
Otter Tail Power Company [Member] | Maximum [Member] | ||
Equity to Total Capitalization Ratio | 58.00% |
Note 8 - Commitments and Cont56
Note 8 - Commitments and Contingencies (Details Textual) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Loss Contingency, Estimate of Possible Loss | $ 1,000,000 | |
Agreement to Lease Rail Cars for Transporting Coal to Hoot Lake Plant [Member] | ||
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year | 243,000 | |
Operating Leases, Future Minimum Payments, Due in Two Years | 324,000 | |
Operating Leases, Future Minimum Payments, Due in Three Years | 324,000 | |
Operating Leases, Future Minimum Payments, Due in Four Years | $ 135,000 | |
Otter Tail Power Company [Member] | ||
Number of Utilities Participating in MISO RSG Proceeding Before FERC | 200 | |
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | ||
Estimated Liability of Refund Obligation | $ 1,600,000 | |
Otter Tail Power Company [Member] | Coal Purchase Commitments 1 [Member] | ||
Contract Expiration Year | 2,041 | |
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member] | ||
Contract Expiration Year | 2,019 | |
Otter Tail Power Company [Member] | Construction Programs [Member] | ||
Contract Expiration Year | 2,019 | 2,019 |
Long-term Purchase Commitment, Amount | $ 37,500,000 | $ 41,000,000 |
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member] | ||
Contract Expiration Year | 2,040 | |
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member] | ||
Long-term Purchase Commitment, Amount | $ 6,200,000 | $ 6,700,000 |
Note 9 - Short-term and Long-57
Note 9 - Short-term and Long-term Borrowings (Details Textual) $ in Billions | Feb. 07, 2018USD ($) |
The 2018 Note Purchase Agreement [Member] | |
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount | 10.00% |
Debt Instrument, Prepayment, Percentage of the Principal Amount Prepaid | 100.00% |
Debt Instrument, Percentage of Principal Amount to be Offered for Prepayment in the Event of a Change of Control | 100.00% |
Otter Tail Power Company [Member] | Series 2018 A senior Unsecured Notes Due February 7, 2048 [Member] | |
Debt Instrument, Face Amount | $ 0.1 |
Debt Instrument, Interest Rate, Stated Percentage | 4.07% |
Note 9 - Short-term and Long-58
Note 9 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Line Limit | $ 300,000 | |
In Use | 30,319 | |
Restricted due to Outstanding Letters of Credit | 300 | |
Available | 269,381 | $ 187,239 |
Otter Tail Corporation Credit Agreement [Member] | ||
Line Limit | 130,000 | |
In Use | 6,182 | |
Restricted due to Outstanding Letters of Credit | ||
Available | 123,818 | 130,000 |
OTP Credit Agreement [Member] | ||
Line Limit | 170,000 | |
In Use | 24,137 | |
Restricted due to Outstanding Letters of Credit | 300 | |
Available | $ 145,563 | $ 57,239 |
Note 9 - Short-term and Long-59
Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Short-Term Debt | $ 30,319 | $ 112,371 |
Long-Term Debt | 592,651 | 492,711 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 171 | 186 |
Unamortized Long-Term Debt Issuance Costs | 2,537 | 2,145 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 589,943 | 490,380 |
Total Short-Term and Long-Term Debt (with current maturities) | 620,433 | 602,937 |
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Long-Term Debt | ||
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | 80,000 | 80,000 |
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Long-Term Debt | 140,000 | 140,000 |
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Long-Term Debt | 30,000 | 30,000 |
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Long-Term Debt | 42,000 | 42,000 |
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Long-Term Debt | 60,000 | 60,000 |
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Long-Term Debt | 50,000 | 50,000 |
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Long-Term Debt | 90,000 | 90,000 |
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Long-Term Debt | 100,000 | |
North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Long-Term Debt | 7 | 27 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | 644 | 684 |
Otter Tail Power Company [Member] | ||
Short-Term Debt | 24,137 | 112,371 |
Long-Term Debt | 512,000 | 412,000 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | ||
Unamortized Long-Term Debt Issuance Costs | 2,091 | 1,684 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 509,909 | 410,316 |
Total Short-Term and Long-Term Debt (with current maturities) | 534,046 | 522,687 |
Otter Tail Power Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Long-Term Debt | ||
Otter Tail Power Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | ||
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Long-Term Debt | 140,000 | 140,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Long-Term Debt | 30,000 | 30,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Long-Term Debt | 42,000 | 42,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Long-Term Debt | 60,000 | 60,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Long-Term Debt | 50,000 | 50,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Long-Term Debt | 90,000 | 90,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Long-Term Debt | 100,000 | |
Otter Tail Power Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | ||
Parent Company [Member] | ||
Short-Term Debt | 6,182 | |
Long-Term Debt | 80,651 | 80,711 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 171 | 186 |
Unamortized Long-Term Debt Issuance Costs | 446 | 461 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 80,034 | 80,064 |
Total Short-Term and Long-Term Debt (with current maturities) | 86,387 | 80,250 |
Parent Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Long-Term Debt | ||
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | 80,000 | 80,000 |
Parent Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Long-Term Debt | ||
Parent Company [Member] | North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Long-Term Debt | 7 | 27 |
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | $ 644 | $ 684 |
Note 9 - Short-term and Long-60
Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 0.90% | |
Long-Term Debt, Due Date | Feb. 5, 2018 | |
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.55% | 3.55% |
Long-Term Debt, Due Date | Dec. 15, 2026 | Dec. 15, 2026 |
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.63% | 4.63% |
Long-Term Debt, Due Date | Dec. 1, 2021 | Dec. 1, 2021 |
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.15% | 6.15% |
Long-Term Debt, Due Date | Aug. 20, 2022 | Aug. 20, 2022 |
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.37% | 6.37% |
Long-Term Debt, Due Date | Aug. 20, 2027 | Aug. 20, 2027 |
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.68% | 4.68% |
Long-Term Debt, Due Date | Feb. 27, 2029 | Feb. 27, 2029 |
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.47% | 6.47% |
Long-Term Debt, Due Date | Aug. 20, 2037 | Aug. 20, 2037 |
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.47% | 5.47% |
Long-Term Debt, Due Date | Feb. 27, 2044 | Feb. 27, 2044 |
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.07% | |
Long-Term Debt, Due Date | Feb. 7, 2048 | |
North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.95% | 3.95% |
Long-Term Debt, Due Date | Apr. 1, 2018 | Apr. 1, 2018 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 2.54% | 2.54% |
Long-Term Debt, Due Date | Mar. 18, 2021 | Mar. 18, 2021 |
Note 10 - Pension Plan and Ot61
Note 10 - Pension Plan and Other Postretirement Benefits (Details Textual) - Pension Plan [Member] - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan, Minimum Funding Requirement | $ 0 | |
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 20,000 |
Note 10 - Pension Plan and Ot62
Note 10 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2018 | Mar. 31, 2017 | ||
Pension Plan [Member] | |||
Service Cost—Benefit Earned During the Period | $ 1,615 | $ 1,407 | |
Interest Cost on Projected Benefit Obligation | 3,363 | 3,534 | |
Expected Return on Assets | (5,300) | (4,807) | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 4 | 30 | |
From Other Comprehensive Income | [1] | 1 | |
Amortization of Net Actuarial Loss: | |||
From Regulatory Asset | 1,784 | 1,273 | |
From Other Comprehensive Income | [1] | 44 | 31 |
Net Periodic Pension Cost | [2] | 1,510 | 1,469 |
Service Cost—Benefit Earned During the Period | 1,615 | 1,407 | |
Interest Cost on Projected Benefit Obligation | 3,363 | 3,534 | |
From Other Comprehensive Income | [1] | 44 | 31 |
From Regulatory Asset | 4 | 30 | |
From Other Comprehensive Income | [1] | 1 | |
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 328 | 285 | |
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 1,247 | 1,100 | |
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 40 | 34 | |
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | (21) | ||
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | (84) | 50 | |
Executive Survivor and Supplemental Retirement Plan [Member] | |||
Service Cost—Benefit Earned During the Period | 100 | 73 | |
Interest Cost on Projected Benefit Obligation | 399 | 422 | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 4 | 4 | |
From Other Comprehensive Income | [3] | 10 | 9 |
Amortization of Net Actuarial Loss: | |||
From Regulatory Asset | 67 | 71 | |
From Other Comprehensive Income | [3] | 165 | 110 |
Net Periodic Pension Cost | [4] | 745 | 689 |
Service Cost—Benefit Earned During the Period | 100 | 73 | |
Interest Cost on Projected Benefit Obligation | 399 | 422 | |
From Other Comprehensive Income | [3] | 165 | 110 |
From Regulatory Asset | 4 | 4 | |
From Other Comprehensive Income | [3] | 10 | 9 |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 25 | 24 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 75 | 49 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 645 | 616 | |
Other Postretirement Benefits Plan [Member] | |||
Service Cost—Benefit Earned During the Period | 382 | 356 | |
Interest Cost on Projected Benefit Obligation | 645 | 678 | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 412 | 233 | |
From Other Comprehensive Income | [1] | 10 | 6 |
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | [5] | 1,449 | 1,273 |
Service Cost—Benefit Earned During the Period | 382 | 356 | |
Interest Cost on Projected Benefit Obligation | 645 | 678 | |
From Regulatory Asset | 412 | 233 | |
From Other Comprehensive Income | [1] | 10 | 6 |
Effect of Medicare Part D Subsidy | (37) | (140) | |
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 78 | 247 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 294 | 278 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 10 | 9 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | 217 | ||
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||
Amortization of Net Actuarial Loss: | |||
Net Periodic Pension Cost | $ 850 | $ 739 | |
[1] | Corporate cost included in nonservice cost components of postretirement benefits. | ||
[2] | Allocation of Costs: Costs included in OTP capital expenditures $ 328 $ 285 Service costs included in electric operation and maintenance expenses 1,247 1,100 Service costs included in other nonelectric expenses 40 34 Nonservice costs capitalized as regulatory assets (21 ) -- Nonservice costs included in nonservice cost components of postretirement benefits (84 ) 50 | ||
[3] | Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company's consolidated statements of income. | ||
[4] | Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 24 Service costs included in other nonelectric expenses 75 49 Nonservice costs included in nonservice cost components of postretirement benefits 645 616 | ||
[5] | Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 247 Service costs included in electric operation and maintenance expenses 294 278 Service costs included in other nonelectric expenses 10 9 Nonservice costs capitalized as regulatory assets 217 -- Nonservice costs included in nonservice cost components of postretirement benefits 850 739 |
Note 11 - Fair Value of Finan63
Note 11 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member] | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Otter Tail Corporation Credit Agreement [Member] | ||
Debt Instrument, Description of Variable Rate Basis | LIBOR | LIBOR |
Debt Instrument, Basis Spread on Variable Rate | 1.50% | 1.50% |
OTP Credit Agreement [Member] | ||
Debt Instrument, Description of Variable Rate Basis | LIBOR | LIBOR |
Debt Instrument, Basis Spread on Variable Rate | 1.25% | 1.25% |
Note 11 - Fair Value of Finan64
Note 11 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Reported Value Measurement [Member] | ||
Cash and Cash Equivalents | $ 1,121 | $ 16,216 |
Short-Term Debt | (30,319) | (112,371) |
Long-Term Debt including Current Maturities | (590,114) | (490,566) |
Estimate of Fair Value Measurement [Member] | ||
Cash and Cash Equivalents | 1,121 | 16,216 |
Short-Term Debt | (30,319) | (112,371) |
Long-Term Debt including Current Maturities | $ (614,873) | $ (543,691) |
Note 13 - Income Tax Expense 65
Note 13 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Period for Unrecognized Tax Benefits Not Expected Change | 1 year |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ 0 |
Note 13 - Income Tax Expense 66
Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Income Before Income Taxes – Continuing Operations | $ 30,009 | $ 25,892 |
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for first quarter 2018, 39% for first quarter 2017) | 7,802 | 10,098 |
Increases (Decreases) in Tax from: | ||
Federal Production Tax Credits | (1,120) | (2,052) |
Property Related Differences and Other Regulatory Adjustments | (1,073) | 105 |
Excess Tax Deduction – Equity Method Stock Awards | (624) | (697) |
Other Comprehensive Income Deferred Tax Rate Adjustment | (531) | |
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258) | (212) |
Research and Development and Other Tax Credits | (180) | (157) |
Allowance for Funds Used During Construction – Equity | (167) | (67) |
Corporate Owned Life Insurance | (8) | (294) |
Section 199 Domestic Production Activities Deduction | (330) | |
Other Items – Net | (47) | (31) |
Income Tax Expense – Continuing Operations | $ 3,794 | $ 6,363 |
Effective Income Tax Rate – Continuing Operations | 12.60% | 24.60% |
Note 13 - Income Tax Expense 67
Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals) | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Composite Federal and State Statutory Rate | 26.00% | 39.00% |
Note 13 - Income Tax Expense 68
Note 13 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Balance, beginning | $ 684 | $ 891 |
Decreases Related to Tax Positions for Prior Years | (44) | |
Increases Related to Tax Positions for Current Year | 36 | 43 |
Uncertain Positions Resolved During Year | ||
Balance, ending | $ 676 | $ 934 |