Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2019 | Oct. 31, 2019 | |
Document Information [Line Items] | ||
Entity Central Index Key | 0001466593 | |
Entity Registrant Name | Otter Tail Corp | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Period Focus | Q3 | |
Document Fiscal Year Focus | 2019 | |
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2019 | |
Document Transition Report | false | |
Entity File Number | 0-53713 | |
Entity Incorporation, State or Country Code | MN | |
Entity Tax Identification Number | 27-0383995 | |
Entity Address, Address Line One | 215 South Cascade Street, Box 496 | |
Entity Address, City or Town | Fergus Falls | |
Entity Address, State or Province | MN | |
Entity Address, Postal Zip Code | 56538-0496 | |
City Area Code | 866 | |
Local Phone Number | 410-8780 | |
Title of 12(b) Security | Common Shares, par value $5.00 per share | |
Trading Symbol | OTTR | |
Security Exchange Name | NASDAQ | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 39,759,054 |
Consolidated Balance Sheets (Cu
Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and Cash Equivalents | $ 921 | $ 861 |
Accounts Receivable: | ||
Trade—Net | 92,189 | 75,144 |
Other | 8,884 | 9,741 |
Inventories | 97,052 | 106,270 |
Unbilled Receivables | 19,020 | 23,626 |
Income Taxes Receivable | 0 | 2,439 |
Regulatory Assets | 12,667 | 17,225 |
Other | 6,926 | 6,114 |
Total Current Assets | 237,659 | 241,420 |
Investments | 9,743 | 8,961 |
Other Assets | 38,996 | 35,759 |
Goodwill | 37,572 | 37,572 |
Other Intangibles—Net | 11,562 | 12,450 |
Regulatory Assets | 130,551 | 135,257 |
Right of Use Assets - Operating Leases | 21,953 | 0 |
Plant | ||
Electric Plant in Service | 2,189,732 | 2,019,721 |
Nonelectric Operations | 238,542 | 228,120 |
Construction Work in Progress | 141,839 | 181,626 |
Total Gross Plant | 2,570,113 | 2,429,467 |
Less Accumulated Depreciation and Amortization | 877,958 | 848,369 |
Net Plant | 1,692,155 | 1,581,098 |
Total Assets | 2,180,191 | 2,052,517 |
Current Liabilities | ||
Short-Term Debt | 108,997 | 18,599 |
Current Maturities of Long-Term Debt | 180 | 172 |
Accounts Payable | 89,360 | 96,291 |
Accrued Salaries and Wages | 19,151 | 24,857 |
Accrued Federal and State Income Taxes | 3,945 | 0 |
Other Accrued Taxes | 13,828 | 17,287 |
Regulatory Liabilities | 6,311 | 738 |
Current Operating Lease Liabilities | 4,006 | 0 |
Other Accrued Liabilities | 7,409 | 12,149 |
Total Current Liabilities | 253,187 | 170,093 |
Pensions Benefit Liability | 75,363 | 98,358 |
Other Postretirement Benefits Liability | 73,668 | 71,561 |
Long-Term Operating Lease Liabilities | 18,384 | 0 |
Other Noncurrent Liabilities | 28,130 | 24,326 |
Commitments and Contingencies (note 9) | ||
Deferred Credits | ||
Deferred Income Taxes | 124,602 | 120,976 |
Deferred Tax Credits | 18,963 | 19,974 |
Regulatory Liabilities | 238,781 | 226,469 |
Other | 2,593 | 1,895 |
Total Deferred Credits | 384,939 | 369,314 |
Capitalization | ||
Long-Term Debt—Net | 590,015 | 590,002 |
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2019—39,755,277 Shares; 2018—39,664,884 Shares | 198,776 | 198,324 |
Premium on Common Shares | 346,294 | 344,250 |
Retained Earnings | 215,931 | 190,433 |
Accumulated Other Comprehensive Loss | (4,496) | (4,144) |
Total Common Equity | 756,505 | 728,863 |
Total Capitalization | 1,346,520 | 1,318,865 |
Total Liabilities and Equity | 2,180,191 | 2,052,517 |
Cumulative Preferred Shares [Member] | ||
Capitalization | ||
Cumulative Shares | 0 | 0 |
Cumulative Preference Shares [Member] | ||
Capitalization | ||
Cumulative Shares | $ 0 | $ 0 |
Consolidated Balance Sheets (_2
Consolidated Balance Sheets (Current Period Unaudited) (Parentheticals) - $ / shares | Sep. 30, 2019 | Dec. 31, 2018 |
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) | 39,755,277 | 39,664,884 |
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 (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Operating Revenues: | ||||
Total Operating Revenues | $ 228,652 | $ 227,662 | $ 703,827 | $ 695,276 |
Operating Expenses | ||||
Production Fuel – Electric | 18,331 | 17,129 | 45,547 | 51,723 |
Electric Operation and Maintenance Expenses | 35,869 | 33,897 | 114,107 | 111,113 |
Cost of Products Sold (depreciation included below) | 88,747 | 93,361 | 277,325 | 275,691 |
Other Nonelectric Expenses | 11,665 | 12,547 | 38,404 | 37,690 |
Depreciation and Amortization | 19,657 | 18,708 | 58,229 | 56,216 |
Property Taxes – Electric | 3,965 | 4,094 | 11,824 | 11,202 |
Total Operating Expenses | 191,397 | 189,400 | 600,184 | 589,294 |
Operating Income | 37,255 | 38,262 | 103,643 | 105,982 |
Interest Charges | 7,539 | 7,549 | 23,190 | 22,597 |
Nonservice Cost Components of Postretirement Benefits | 1,055 | 1,326 | 3,165 | 4,129 |
Other Income | 1,020 | 1,245 | 3,114 | 3,135 |
Income Before Income Taxes | 29,681 | 30,632 | 80,402 | 82,391 |
Income Tax Expense | 4,936 | 7,359 | 13,907 | 14,207 |
Net Income | $ 24,745 | $ 23,273 | $ 66,495 | $ 68,184 |
Average Number of Common Shares Outstanding – Basic (in shares) | 39,714,672 | 39,621,524 | 39,694,677 | 39,592,705 |
Average Number of Common Shares Outstanding – Diluted (in shares) | 39,946,739 | 39,903,565 | 39,922,580 | 39,882,105 |
Basic Earnings Per Common Share (in dollars per share) | $ 0.62 | $ 0.59 | $ 1.68 | $ 1.72 |
Diluted Earnings Per Common Share (in dollars per share) | $ 0.62 | $ 0.58 | $ 1.67 | $ 1.71 |
Electricity [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | $ 115,285 | $ 105,749 | $ 346,291 | $ 334,858 |
Changes in Accrued Revenues under Alternative Revenue Programs | (921) | (317) | (1,601) | (2,757) |
Total Electric Revenues | 114,364 | 105,432 | 344,690 | 332,101 |
Product [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | 114,288 | 122,230 | 359,137 | 363,175 |
Electricity, Purchased [Member] | ||||
Operating Expenses | ||||
Purchased Power – Electric System Use | $ 13,163 | $ 9,664 | $ 54,748 | $ 45,659 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Net Income | $ 24,745 | $ 23,273 | $ 66,495 | $ 68,184 |
Unrealized Gain (Loss) on Available-for-Sale Securities: | ||||
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period | (1) | 4 | (5) | (106) |
Unrealized Gains (Losses) Arising During Period | 30 | (14) | 187 | (93) |
Income Tax (Expense) Benefit | (6) | 2 | (38) | 42 |
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | 23 | (8) | 144 | (157) |
Pension and Postretirement Benefit Plans: | ||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 130 | 232 | 389 | 692 |
Income Tax Expense | (34) | (60) | (101) | (180) |
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act | 0 | 0 | 0 | (531) |
Pension and Postretirement Benefit Plans – net-of-tax | 96 | 172 | 288 | (19) |
Total Other Comprehensive Income (Loss) | 119 | 164 | 432 | (176) |
Total Comprehensive Income | $ 24,864 | $ 23,437 | $ 66,927 | $ 68,008 |
Consolidated Statements of Comm
Consolidated Statements of Common Shareholders' Equity (Unaudited) - USD ($) $ in Thousands | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | AOCI Attributable to Parent [Member] | Total |
Balance (in shares) at Dec. 31, 2017 | 39,557,491 | ||||
Balance at Dec. 31, 2017 | $ 197,787 | $ 343,450 | $ 161,286 | $ (5,631) | $ 696,892 |
Common Stock Issuances, Net of Expenses (in shares) | 178,601 | ||||
Common Stock Issuances, Net of Expenses | $ 893 | (93) | |||
Common Stock Issuances, Net of Expenses | (986) | ||||
Net Income | 68,184 | 68,184 | |||
Other Comprehensive Income (Loss) | (176) | (176) | |||
Employee Stock Incentive Plan Expense | 3,402 | 3,402 | |||
Common Dividends | (39,895) | (39,895) | |||
Common Stock Retirements (in shares) | (71,208) | ||||
Common Stock Retirements | $ (356) | (2,656) | (3,012) | ||
Balance (in shares) at Sep. 30, 2018 | 39,664,884 | ||||
Balance at Sep. 30, 2018 | $ 198,324 | 343,210 | 189,575 | (5,807) | 725,302 |
Balance (in shares) at Jun. 30, 2018 | 39,651,436 | ||||
Balance at Jun. 30, 2018 | $ 198,257 | 342,690 | 179,605 | (5,971) | 714,581 |
Common Stock Issuances, Net of Expenses (in shares) | 25,225 | ||||
Common Stock Issuances, Net of Expenses | $ 126 | 0 | |||
Common Stock Issuances, Net of Expenses | (126) | ||||
Net Income | 23,273 | 23,273 | |||
Other Comprehensive Income (Loss) | 164 | 164 | |||
Employee Stock Incentive Plan Expense | 1,149 | 1,149 | |||
Common Dividends | (13,303) | (13,303) | |||
Common Stock Retirements (in shares) | (11,777) | ||||
Common Stock Retirements | $ (59) | (503) | (562) | ||
Balance (in shares) at Sep. 30, 2018 | 39,664,884 | ||||
Balance at Sep. 30, 2018 | $ 198,324 | 343,210 | 189,575 | (5,807) | 725,302 |
Balance (in shares) at Dec. 31, 2018 | 39,664,884 | ||||
Balance at Dec. 31, 2018 | $ 198,324 | 344,250 | 190,433 | (4,144) | 728,863 |
Common Stock Issuances, Net of Expenses (in shares) | 145,617 | ||||
Common Stock Issuances, Net of Expenses | $ 728 | (19) | |||
Common Stock Issuances, Net of Expenses | (747) | ||||
Net Income | 66,495 | 66,495 | |||
Other Comprehensive Income (Loss) | 432 | 432 | |||
Employee Stock Incentive Plan Expense | 5,245 | 5,245 | |||
Common Dividends | (41,781) | (41,781) | |||
Common Stock Retirements (in shares) | (55,224) | ||||
Common Stock Retirements | $ (276) | (2,454) | (2,730) | ||
ASU 2018-02 2017 TCJA Stranded Tax Transfer | 784 | (784) | |||
Balance (in shares) at Sep. 30, 2019 | 39,755,277 | ||||
Balance at Sep. 30, 2019 | $ 198,776 | 346,294 | 215,931 | (4,496) | 756,505 |
Balance (in shares) at Jun. 30, 2019 | 39,754,902 | ||||
Balance at Jun. 30, 2019 | $ 198,775 | 345,030 | 205,115 | (4,615) | 744,305 |
Common Stock Issuances, Net of Expenses (in shares) | 375 | ||||
Common Stock Issuances, Net of Expenses | $ 1 | (36) | |||
Common Stock Issuances, Net of Expenses | (37) | ||||
Net Income | 24,745 | 24,745 | |||
Other Comprehensive Income (Loss) | 119 | 119 | |||
Employee Stock Incentive Plan Expense | 1,301 | 1,301 | |||
Common Dividends | (13,929) | (13,929) | |||
Balance (in shares) at Sep. 30, 2019 | 39,755,277 | ||||
Balance at Sep. 30, 2019 | $ 198,776 | $ 346,294 | $ 215,931 | $ (4,496) | $ 756,505 |
Consolidated Statements of Co_2
Consolidated Statements of Common Shareholders' Equity (Unaudited) (Parentheticals) - $ / shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Retained Earnings [Member] | ||||
Dividends Declared Per Common Share (in dollars per share) | $ 0.35 | $ 0.335 | $ 1.05 | $ 1.005 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Cash Flows from Operating Activities | ||
Net Income | $ 66,495 | $ 68,184 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Depreciation and Amortization | 58,229 | 56,216 |
Deferred Tax Credits | (1,011) | (1,054) |
Deferred Income Taxes | 3,487 | 7,529 |
Change in Deferred Debits and Other Assets | 7,142 | 10,641 |
Discretionary Contribution to Pension Plan | (22,500) | (20,000) |
Change in Noncurrent Liabilities and Deferred Credits | 10,344 | (191) |
Allowance for Equity/Other Funds Used During Construction | (1,602) | (1,586) |
Stock Compensation Expense—Equity Awards | 5,245 | 3,402 |
Other—Net | 312 | (201) |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (16,213) | (27,804) |
Change in Inventories | 9,218 | (6,581) |
Change in Other Current Assets | 2,974 | 3,827 |
Change in Payables and Other Current Liabilities | (20,744) | 5,546 |
Change in Interest and Income Taxes Receivable/Payable | 3,773 | 2,932 |
Net Cash Provided by Operating Activities | 105,149 | 100,860 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (149,695) | (74,489) |
Net Proceeds from Disposal of Noncurrent Assets | 4,111 | 1,879 |
Cash Used for Investments and Other Assets | (5,546) | (3,324) |
Net Cash Used in Investing Activities | (151,130) | (75,934) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | 383 | (7) |
Net Short-Term Borrowings (Repayments) | 90,398 | (96,882) |
Payments for Retirement of Capital Stock and Common Stock Issuance Expenses | (2,765) | (3,120) |
Proceeds from Issuance of Long-Term Debt | 0 | 100,000 |
Short-Term and Long-Term Debt Issuance Expenses | (66) | (441) |
Payments for Retirement of Long-Term Debt | (128) | (148) |
Dividends Paid | (41,781) | (39,895) |
Net Cash Provided by (Used in) Financing Activities | 46,041 | (40,493) |
Net Change in Cash and Cash Equivalents | 60 | (15,567) |
Cash and Cash Equivalents at Beginning of Period | 861 | 16,216 |
Cash and Cash Equivalents at End of Period | $ 921 | $ 649 |
Note 1 - Summary of Significant
Note 1 - Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Significant Accounting Policies and New Accounting Pronouncements [Text Block] | 1. Revenue Recognition 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 customer’s specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, Reg ul ated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR, Phase-in Rate Plan and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three nine September 30, 2019 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 30, 2019 2018. Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 third may Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 September 30, 2019 Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2018 not The following table indicates there were no changes to goodwill by business segment during the first nine 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059 New Accounting Standards Adopted ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 2016 02 December 15, 2018, 842 2016 02 January 1, 2019. 8 ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income 220 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2018 02 December 15, 2018, 2018 02 The Company adopted the updates in ASU 2018 02 January 1, 2019, not Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below. (in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 ) 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. 2017 04 first 2019. no no New Accounting Standards Pending Adoption ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , may 326 December 15, 2019. not ASU 201 8 - 1 5 August 2018 No. 2018 15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350 40 , 350 40, Internal-Use Software 2018 15 2018 15 350 40 2018 15 2018 15 December 15, 2019 2018 15 first 2020 no |
Note 2 - Segment Information
Note 2 - Segment Information | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Segment Reporting Disclosure [Text Block] | 2. Segment Information The accounting policies of the segments are described under note 1 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, material handling components and extruded raw material stock. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation. The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not While no single customer accounted for over 10% 2018, 2018 2018 2018 2018 2018 2018 one All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.5% and 98.1% of operating revenues for the respective three September 30, 2019 2018, nine September 30, 2019 2018. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three nine September 30, 2019 2018 September 30, 2019 December 31, 2018 Operating Revenue Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 100,345 $ 88,750 $ 303,276 $ 287,330 Changes in Accrued ARP Revenues (921 ) (317 ) (1,601 ) (2,757 ) Total Retail Sales Revenue 99,424 88,433 301,675 284,573 Transmission Services Revenue 11,692 12,569 34,023 35,785 Wholesale Revenues – Company Generation 1,631 2,826 4,099 6,380 Other Revenues 1,626 1,614 4,929 5,394 Total Electric Segment Revenues 114,373 105,442 344,726 332,132 Manufacturing Segment: Metal Parts and Tooling 56,255 55,864 185,520 170,179 Plastic Products and Tooling 8,088 8,790 26,486 26,986 Other 1,379 2,373 5,034 6,678 Total Manufacturing Segment Revenues 65,722 67,027 217,040 203,843 Plastics Segment – Sale of PVC Pipe Products 48,566 55,203 142,100 159,332 Intersegment Eliminations (9 ) (10 ) (39 ) (31 ) Total $ 228,652 $ 227,662 $ 703,827 $ 695,276 Interest Charges Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,300 $ 6,509 $ 19,566 $ 19,586 Manufacturing 561 555 1,791 1,664 Plastics 197 150 561 460 Corporate and Intersegment Eliminations 481 335 1,272 887 Total $ 7,539 $ 7,549 $ 23,190 $ 22,597 Income Taxes Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 4,066 $ 5,172 $ 9,874 $ 7,881 Manufacturing 285 799 2,888 3,040 Plastics 1,914 2,276 5,287 6,897 Corporate (1,329 ) (888 ) (4,142 ) (3,611 ) Total $ 4,936 $ 7,359 $ 13,907 $ 14,207 Net Income (Loss) Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 17,682 $ 14,567 $ 43,884 $ 41,835 Manufacturing 3,155 3,022 11,987 10,769 Plastics 5,397 6,432 14,918 19,505 Corporate (1,489 ) (748 ) (4,294 ) (3,925 ) Total $ 24,745 $ 23,273 $ 66,495 $ 68,184 Identifiable Assets September 30, December 31, (in thousands) 2019 2018 Electric $ 1,829,271 $ 1,728,534 Manufacturing 206,835 187,556 Plastics 97,459 91,630 Corporate 46,626 44,797 Total $ 2,180,191 $ 2,052,517 |
Note 3 - Rate and Regulatory Ma
Note 3 - Rate and Regulatory Matters | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Public Utilities Disclosure [Text Block] | 3. Below are descriptions of OTP’s major capital expenditure projects that have had, or are expected to 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 2019 2018. Major Capital Expenditure Projects Astoria Station 2021. November 3, 2017, August 3, 2018 Station. In a September 26, 2018 March 6, 2019 December 2018 January 2019. May 2019. September 30, 2019, Merricourt Wind Energy Center (Merricourt) November 16, 2016 November 16, 2016, October 26, 2017 January 10, 2018. November 3, 2017. March 6, 2019 April 2019. In connection with action by the FERC, OTP and EDF agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, July 16, 2019, August 2019. September 30, 2019, Big Stone South–Ellendale Multi-Value Transmission Project (MVP) February 6, 2019, December 2011. Recovery of OTP’s major transmission investments is through the MISO Tariff and Minnesota, North Dakota and South Dakota base rates and TCR riders. Minnesota General Rates 2016 March 2017 May 1, 2017. The MPUC’s order also included: ( 1 2 November 1, 2017. Minnesota Conservation Improvement Programs (MNCIP) not May 25, 2016 2017 2018 2019 2017 2018 2019 May 20, 2019 2017 2019 one 2020. On April 1, 2019 2018 2018 not May 31, 2019 2018 June 24, 2019 $3.0 October 24, 2019 2018. Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 March 11, 2019. On November 30, 2018 two two 2019. April 1, 2019, not September 30, 2019 Environmental Cost Recovery Rider 2010 2016 November 2017. 2018 zero December 1, 2018. March April 2019. Renewable Resource Adjustment November 1, 2017, 2017 2018. June 21, 2019 September 30, 2019 Fuel and Purchased Power Costs Recovery December 2017 July 31, 2019 twelve January 1, 2020. On implementation of the new mechanism, OTP will be required to accrue a liability and likely refund amounts of fuel and purchased power and related costs per kwh collected in excess of forecasted amounts per kwh submitted to the MPUC for setting rates for the upcoming year. OTP will continue to accrue revenue and a regulatory asset for fuel and purchased power costs incurred in excess of amounts recovered, that it expects to recover under the adjustment mechanism, unless and until recovery of those excess amounts are deemed not not North Dakota General Rates November 2, 2017 December 20, 2017 January 1, 2018. February 27, 2018 March 1, 2018. On March 23, 2018 In a September 26, 2018 March 2018 not February 1, 2019, April 2019 Renewable Resource Adjustment Effective in February 2019 2017 Transmission Cost Recovery Rider 2017 26 26A 2017 OTP filed its annual update to the North Dakota TCR rider on August 30, 2019 January 1, 2020. Environmental Cost Recovery Rider 2017 February 1, 2019, February 1, 2019 October 22, 2019 zero November 1, 2019 December 31, 2019. Generation Cost Recovery Rider March 1, 2019 May 15, 2019. July 1, 2019. South Dakota General Rates April 20, 2018 first two October 18, 2018. second The SDPUC approved a partial settlement on March 1, 2019 second January 1, 2018 October 17, 2018 first 2019. May 14, 2019. May 30, 2019 June 28, 2019 August 1, 2019. October 18, 2018 October 2019 On July 9, 2019 2018 May 30, 2019 first October 18, 2018, October 1, 2019. To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 30 Transmission Cost Recovery Rider January 29, 2018 October 18, 2018, 2018 OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. February 20, 2019 March 1, 2019. January 1, 2019 January 2020. OTP made a supplemental filing for the South Dakota TCR rider on September 5, 2019 2018 September 17, 2019 October 1, 2019. Environmental Cost Recovery Rider October 18, 2018 October 2019 Phase-In Rate Plan Rider May 31, 2019 OTP made a supplemental filing for the South Dakota Phase-In Rate Plan Rider on August 2, 2019. August 21, 2019 September 1, 2019. Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota. Three Months Ended September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives $ 1,518 $ 1,488 $ 4,246 $ 4,300 Renewable Resource Recovery 1,316 817 3,949 2,001 Transmission Cost Recovery (284 ) (1,196 ) 301 (1,683 ) Environmental Cost Recovery - 24 (1 ) (25 ) North Dakota Transmission Cost Recovery 908 1,922 3,554 5,149 Renewable Resource Adjustment (20 ) 2,220 616 6,266 Generation Cost Recovery 137 - 607 - Environmental Cost Recovery (7 ) 1,823 556 5,474 South Dakota Transmission Cost Recovery 743 496 1,587 1,282 Conservation Improvement Program Costs and Incentives 100 238 440 589 Phase-In Rate Plan Recovery (10 ) - (10 ) - Environmental Cost Recovery (2 ) 545 (29 ) 1,580 Total $ 4,399 $ 8,377 $ 15,816 $ 24,933 Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2017 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2018 Incentive and Cost Recovery A – October 24, 2019 December 1, 2019 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536 /kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ - 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2019 Annual Update – Revised R – September 30, 2019 November 1, 2019 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $0.00049 /kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 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 Transmission Cost Recovery 2019 Annual Update R – August 30, 2019 January 1, 2020 $ 5,739 Various 2018 Supplemental Update A – December 6, 2018 February 1, 2019 $ 4,801 Various 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 Environmental Cost Recovery 2019 Update A – October 22, 2019 November 1, 2019 $ - 0% of base 2018 Update A – December 19, 2018 February 1, 2019 $ (378 ) -0.310% of base 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 Generation Cost Recovery 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2019 Rate Reset A – September 17, 2019 October 1, 2019 $ 2,046 Various 2019 Annual Update A – February 20, 2019 March 1, 2019 $ 1,638 Various 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483 /kwh Phase-In Rate Plan Recovery 2019 Initial Request A – August 21, 2019 September 1, 2019 $ 864 3.345% of base TCJA The TCJA, passed in December 2017, January 1, 2018. The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. August 9, 2018 December 5, 2018 one ten 2017 June 1, 2019. one January 2018 May 2019 August September 2019. As described above, OTP’s recent general rate cases in North Dakota and South Dakota reflected the impact of the TCJA in interim rates. OTP accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurred under the lower federal tax rates in the TCJA. The North Dakota liability of $0.8 million as of March 31, 2019 January February 2018 April 2019. As of September 30, 2019, March 15, 2018, 2018 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 MVPs ROE November 12, 2013 may 15 November 12, 2013 February 11, 2015. December 22, 2015 September 28, 2016 September 2016 On November 6, 2014 January 5, 2015 November 12, 2013 0.5% September 28, 2016. On February 12, 2015 may second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 second Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, first 15 February June 2017 2016 December 31, 2016 September 30, 2019. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second On October 16, 2018 April 2017. 206 November 15, 2018, two February 13, 2019 April 10, 2019. no September 30, 2019 second On March 1, 2019 two 2019, |
Note 4 - Regulatory Assets and
Note 4 - Regulatory Assets and Liabilities | 9 Months Ended |
Sep. 30, 2019 | |
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 980. 980 605 25 September 30, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 113,657 $ 120,012 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,571 7,571 asset lives Conservation Improvement Program Costs and Incentives 2 243 5,339 5,582 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,856 - 2,856 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,525 1,525 asset lives Deferred Marked-to-Market Losses 1 972 186 1,158 15 Big Stone II Unrecovered Project Costs – Minnesota 1 706 409 1,115 19 Debt Reacquisition Premiums 1 203 598 801 156 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 60 711 771 27 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 418 - 418 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 234 350 36 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 339 - 339 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 270 270 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 193 - 193 5 Recoverable Fuel and Purchased Power Costs – South Dakota 1 124 - 124 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 78 - 78 9 Deferred Lease Expenses 1 - 51 51 42 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 3 Total Regulatory Assets $ 12,667 $ 130,551 $ 143,218 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,337 $ 141,337 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 96,981 96,981 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 3,836 - 3,836 3 North Dakota Renewable Resource Recovery Rider Accrued Refund 684 - 684 8 North Dakota Transmission Cost Recovery Rider Accrued Refund 601 - 601 2 North Dakota Environmental Cost Recovery Rider Accrued Refund 537 - 537 2 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 342 342 see below Refundable Fuel Clause Adjustment Revenues – North Dakota 305 - 305 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 140 47 187 15 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 151 - 151 12 South Dakota Phase-In Rate Plan Rider Accrued Refund 39 - 39 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 12 - 12 12 Other 6 74 80 171 Total Regulatory Liabilities $ 6,311 $ 238,781 $ 245,092 Net Regulatory Asset/(Liability) Position $ 6,356 $ (108,230 ) $ (101,874 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 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 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 - 444 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 - 178 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 Deferred Income Taxes 1 - 2,423 2,423 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 - 452 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 - 328 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 - 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ - $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,229 83,229 asset lives Refundable Fuel Clause Adjustment Revenues 121 - 121 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 177 - 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 - 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up - 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 - 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 - 207 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 ) 1 Costs subject to recovery without a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date. 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. All Deferred Marked-to-Market Losses recorded as of the balance sheet date relate to forward purchases of energy scheduled for delivery through 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 156 MISO Schedule 26/26A 26/26A South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in South Dakota and are currently being recovered beginning with the establishment of interim rates in October 2018. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s most recent rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018. The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that had not The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that were recoverable from South Dakota customers as of the balance sheet date. North Dakota Generation Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investment in Astoria Station, a natural gas-fired combustion turbine generation facility under construction near Astoria, South Dakota. The balance represents amounts subject to recovery from North Dakota customers that had not Deferred Lease Expenses: Under ASC 842 The Minnesota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that were recoverable from Minnesota customers as of the balance sheet date. The regulatory asset and liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that were recoverable from Minnesota customers as of the balance sheet date. 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 were subject to recovery from other Minnesota customers as of the balance sheet date. 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 were recoverable from North Dakota customers as of the balance sheet date. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that were refundable to North Dakota customers as of the balance sheet date. 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 were refundable to North Dakota customers as of the balance sheet date. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that were refundable to North Dakota customers as of the balance sheet date. Effective February 1, 2019 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. The Minnesota Energy Intensive Trade Exposed Rider Accrued Refund relates to over-collected amounts from Minnesota retail customers for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that were subject to refund to Minnesota customers as of the balance sheet date. The South Dakota Phase-In Rate Plan Rider Accrued Refund relates to amounts collected for actual and forecasted costs for Astoria Station, Merricourt, and additional load growth that were refundable to South Dakota customers as of the balance sheet date. The Minnesota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that were refundable to Minnesota customers as of the balance sheet date. 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 were refundable to South Dakota customers as of the balance sheet date. 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 were refundable to South Dakota customers as of the balance sheet date. |
Note 5 - Common Shares and Earn
Note 5 - Common Shares and Earnings Per Share | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Stockholders Equity and Earnings per Share [Text Block] | 5. Shelf Registration On May 3, 2018 may May 3, 2021. Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2018 September 30, 2019: Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 27,125 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, September 30, 2019 39,755,277 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three nine September 30, 2019 2018. not Three Months ended September 30, Nine Months ended September 30, 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,714,672 39,621,524 39,694,677 39,592,705 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 149,023 206,268 147,106 210,691 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 68,138 58,680 63,902 58,475 Nonvested Restricted Shares 13,107 14,761 14,896 17,712 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,799 2,332 1,999 2,522 Total Dilutive Shares 232,067 282,041 227,903 289,400 Weighted Average Common Shares Outstanding – Diluted 39,946,739 39,903,565 39,922,580 39,882,105 The effect of dilutive shares on earnings per share for the three nine September 30, 2019 2018, no $0.01 |
Note 6 - Share-based Payments
Note 6 - Share-based Payments | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Share-based Payment Arrangement [Text Block] | 6. Stock Incentive Awards The following stock incentive awards were granted under the 2014 nine September 30, 2019: Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted: Under Executive and Select Employee Agreements February 13, 2019 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement February 13, 2019 7,800 $ 45.885 December 31, 2021 Restricted Stock Units Granted to Executive Officers February 13, 2019 15,600 $ 49.6225 25% per year through February 6, 2023 Restricted Stock Units Granted to Key Employees April 8, 2019 13,270 $ 44.45 100% on April 8, 2023 Restricted Stock Granted to Nonemployee Directors April 8, 2019 15,700 $ 49.73 33% per year through April 8, 2022 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration on retirement in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price per share on the date of grant. The grant-date fair value of each restricted stock unit granted to a key employee that is not Under the performance share awards the aggregate award for performance at target is 55,600 shares. For target performance the participants would earn an aggregate of 27,800 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. The participants would also earn an aggregate of 27,800 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2019 December 31, 2021, January 1, 2019 20 January 1, 2022. may zero no 718, Compensation – Stock Compensation Under the 2019 The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the earlier of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. Employee Stock Purchase Plan In July 2019 15% six 718, Compensation–Stock Compensation 718 As of September 30, 2019, Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three nine September 30, 2019 2018 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 743 $ 718 $ 3,274 $ 2,037 Restricted Stock Units Granted to Executive Officers 189 174 999 596 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 203 165 572 496 Restricted Stock Units Granted to Key Employees 112 92 346 257 ESPP (15% discount) 54 - 54 - Totals $ 1,301 $ 1,149 $ 5,245 $ 3,402 |
Note 7 - Retained Earnings and
Note 7 - Retained Earnings and Dividend Restriction | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Retained Earnings Restrictions [Text Block] | 7. and Dividend Restriction The Company is a holding company with no Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not September 30, 2019, 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 46.0% and 56.2% based on OTP’s 2019 July 19, 2019. September 30, 2019, 2019 |
Note 8 - Leases
Note 8 - Leases | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Lessee, Operating Leases [Text Block] | 8. The Company adopted ASU 2016 02 842 January 1, 2019, not 842 12 $20 January 1, 2019. not not The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows for the carry forward of lease classifications determined under the requirements of ASC Topic 840. not The Company enters into leases for coal rail cars, warehouse and office space, land and certain office, manufacturing and material handling equipment under varying terms and conditions. The lengths of the leases vary from less than one ten None January 1, 2019, 50 no The right-of-use asset operating leases in place at the time of adoption were capitalized on the basis of their remaining payment obligation balances, discounted to present value based on the Company’s incremental borrowing rates (IBRs) appropriate to the leased asset and lease terms. The remaining payments for operating lease right-of-use assets are being charged to expense on a straight-line basis over the life of the lease. For the Company’s current lease obligations, no no The breakdown of right-of-use assets and lease liabilities as of September 30, 2019 (in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,557 $ 19,967 $ 666 $ 769 $ 24,959 Accumulated Amortization (778 ) (1,836 ) (294 ) (98 ) (3,006 ) Net of Accumulated Amortization $ 2,779 $ 18,131 $ 372 $ 671 $ 21,953 Obligations: Current Operating Lease Liabilities $ 985 $ 2,541 $ 326 $ 154 $ 4,006 Long-Term Operating Lease Liabilities 2,081 15,686 45 572 18,384 Total Lease Liabilities $ 3,066 $ 18,227 $ 371 $ 726 $ 22,390 The amounts of the Company’s right-of-use operating lease obligations as of September 30, 2019 five 2019 2023 2023 (in thousands) Right-of-Use Operating Leases OTP Nonelectric Total 2019 $ 275 $ 1,029 $ 1,304 2020 1,115 3,883 4,998 2021 1,100 3,619 4,719 2022 206 3,491 3,697 2023 196 3,203 3,399 Beyond 2023 448 7,979 8,427 Total Minimum Obligations $ 3,340 $ 23,204 $ 26,544 Interest Component of Obligations (274 ) (3,880 ) (4,154 ) Present Value of Minimum Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 6.2 years and the weighted-average discount rate is 5.3%. A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 January 1, 2019 September 30, 2019 (in thousands) OTP Nonelectric Total Operating Lease Obligations, January 1, 2019 $ 3,609 $ 16,760 $ 20,369 Non-cash Acquisition of Right-of-Use Assets 177 5,115 5,292 Lease Modifications - (164 ) (164 ) Lease Obligation Payments (845 ) (3,086 ) (3,931 ) Interest Component of Lease Obligation Payment 125 699 824 Operating Lease Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 The lease modifications in the above table relate to reductions in future minimum lease obligations on several units of leased equipment at BTD. OTP has obligations to make future operating lease payments primarily related to coal rail-car leases. OTP’s rail-car lease payments are charged to fuel inventory and then expensed to production fuel – electric as a component of fuel cost when fuel is burned. OTP also leases office and operating equipment with lease payments charged to rent expense and reported in electric operation and maintenance expenses on the Company’s consolidated statements of income. From time to time, OTP will lease construction equipment or land for lay-down yards for materials used on capital projects. These leases are generally short term in nature with the lease payments being charged to the related construction project and included in CWIP or plant in service after the project is completed and placed in service. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. These payments are charged to rent expense accounts and reported in costs of goods sold or other nonelectric expenses, as appropriate, on the Company’s consolidated statements of income. The allocation of right-of-use asset and variable lease costs, including non-cash costs related to straight-line amortization of escalating lease payments, for the three nine September 30, 2019 Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost Variable Lease Cost Total Lease Cost Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ - $ 9 $ 29 $ - $ 29 Inventory 244 - 244 707 - 707 Cost of Products Sold 963 65 1,028 2,942 137 3,079 Electric Operation and Maintenance Expenses 64 - 64 194 - 194 Other Nonelectric Expenses 51 (1 ) 50 156 - 156 Total $ 1,331 $ 64 $ 1,395 $ 4,028 $ 137 $ 4,165 |
Note 9 - Commitments and Contin
Note 9 - Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | 9. Construction and Other Purchase Commitments At September 30, 2019 December 31, 2018 2019 2020 2021. 2019 2019 At December 31, 2018 December 31, 2021 October 1, 2019 six January 1, 2020. no not six Electric Utility Capacity and Energy Requirements and Coal Purchase and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2042. OTP also has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Coyote Station expire at the end of 2040. OTP’s current coal purchase agreements for Big Stone Plant expire at the end of 2020. OTP has an agreement with Peabody COALSALES, LLC for the purchase of subbituminous coal for Big Stone Plant’s coal requirements through December 31, 2020. no December 31, 2023. no October 2019, two October, two seventy-five OTP Land Easements OTP has commitments to make future payments for land easements not Contingencies OTP had a $1.6 million refund liability on its balance sheet as of September 30, 2019 3 Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the potential ROE refund described above, the most significant contingencies that could impact the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed established reserve amounts, and litigation matters. In 2015 111 not 2016. 2017, April 2018. On August 21, 2018 September 6, 2019, two not 2022 Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of September 30, 2019, not |
Note 10 - Short-term and Long-t
Note 10 - Short-term and Long-term Borrowings | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Debt Disclosure [Text Block] | 10. The following table presents the status of the Company’s lines of credit as of September 30, 2019 December 31, 2018: (in thousands) Line Limit In Use on September 30, 2019 Restricted due to Outstanding Letters of Credit Available on September 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 35,837 $ - $ 94,163 $ 120,785 OTP Credit Agreement 170,000 73,160 16,561 80,279 160,316 Total $ 300,000 $ 108,997 $ 16,561 $ 174,442 $ 281,101 On October 31, 2019 one October 31, 2023 October 31, 2024 4.2 4.3 10 The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of September 30, 2019 December 31, 2018: September 30, 2019 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 73,160 $ 35,837 $ 108,997 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 PACE Note, 2.54%, due March 18, 2021 394 394 Total $ 512,000 $ 80,394 $ 592,394 Less: Current Maturities net of Unamortized Debt Issuance Costs - 180 180 Unamortized Long-Term Debt Issuance Costs 1,830 369 2,199 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,170 $ 79,845 $ 590,015 Total Short-Term and Long-Term Debt (with current maturities) $ 583,330 $ 115,862 $ 699,192 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 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 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs - 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773 Long-Term Debt Issuances 201 9 Note Purchase Agreement On September 12, 2019, 2019 2019A October 10, 2029 ( 2019A 2019B October 10, 2039 ( 2019B 2019C October 10, 2049 ( 2019C 2020A February 25, 2030 ( 2020A 2020B August 20, 2030 ( 2020B 2020C February 25, 2040 ( 2020C 2020D February 25, 2050 ( 2020D 2019A 2019B 2019C 2020A 2020B 2020C On October 10, 2019, 2019A 2019B 2019C 2019 2019 2020A 2020C 2020D February 25, 2020, 2020B August 20, 2020, OTP may 2019 not 2019 no 2019 2019A April 10, 2029, ( 2019B April 10, 2039 2019C April 10, 2049 2019 2019 The 2019 2019 may not 2019 2019 2019 not 2019 not 2019 2019 2019 2019 2019 no The 2019 4.1 10 |
Note 11 - Pension Plan and Othe
Note 11 - Pension Plan and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | 1 1 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 $ 4,119 $ 4,845 Interest Cost on Projected Benefit Obligation 3,603 3,363 10,809 10,089 Expected Return on Assets (5,324 ) (5,300 ) (15,973 ) (15,899 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 4 12 From Other Comprehensive Income 1 2 - 6 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 3,488 5,351 From Other Comprehensive Income 1 26 46 79 137 Net Periodic Pension Cost 2 $ 844 $ 1,512 $ 2,532 $ 4,535 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in n onservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 ) Cash flows no December 31, 2018 January 2019 September 2019. Executive Survivor and Supplemental Retirement Plan Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 313 $ 300 Interest Cost on Projected Benefit Obligation 433 399 1,301 1,197 Amortization of Prior-Service Cost: From Regulatory Asset 2 4 4 12 From Other Comprehensive Income 1 4 10 12 29 Amortization of Net Actuarial Loss: From Regulatory Asset 31 66 93 200 From Other Comprehensive Income 1 87 166 262 496 Net Periodic Pension Cost 2 $ 661 $ 745 $ 1,985 $ 2,234 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in n onservice cost components of postretirement benefits 557 645 1,672 1,934 Other Postretirement Benefits Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 $ 964 $ 1,145 Interest Cost on Projected Benefit Obligation 770 646 2,312 1,937 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 1,178 1,236 From Other Comprehensive Income 1 10 11 29 32 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,451 $ 4,483 $ 4,350 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) $ (134 ) $ (110 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in n onservice cost components of postretirement benefits 889 768 2,614 2,436 |
Note 12 - Fair Value of Financi
Note 12 - Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Fair Value Disclosures [Text Block] | 1 2 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt September 30, 2019 December 31, 2018 1.50% Long-Term Debt including Current Maturities 2 820. September 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 921 $ 921 $ 861 $ 861 Short-Term Debt (108,997 ) (108,997 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,195 ) (663,761 ) (590,174 ) (601,513 ) |
Note 13 - Property, Plant and E
Note 13 - Property, Plant and Equipment | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Property, Plant and Equipment Disclosure [Text Block] | 13. No |
Note 14 - Income Tax Expense
Note 14 - Income Tax Expense | 9 Months Ended |
Sep. 30, 2019 | |
Notes to Financial Statements | |
Income Tax Disclosure [Text Block] | 1 4 . Income Tax Expense The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income before income taxes and income tax expense reported on the Company’s consolidated statements of income for the three nine September 30, 2019 2018: Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 29,681 $ 30,632 $ 80,402 $ 82,391 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 7,717 $ 7,964 $ 20,905 $ 21,422 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (933 ) (838 ) (2,690 ) (2,932 ) Research and Development Tax Credits (612 ) (202 ) (987 ) (562 ) Excess Tax Deduction – Equity Method Stock Awards - (73 ) (827 ) (698 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (774 ) (774 ) Reconciliation and Prior Period Adjustments (688 ) 2,109 (722 ) 2,028 Corporate Owned Life Insurance (50 ) (332 ) (609 ) (360 ) Allowance for Funds Used During Construction – Equity (239 ) (138 ) (419 ) (416 ) Federal Production Tax Credits - (707 ) - (2,757 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (1 ) (166 ) 30 (213 ) Income Tax Expense $ 4,936 $ 7,359 $ 13,907 $ 14,207 Effective Income Tax Rate 16.6 % 24.0 % 17.3 % 17.2 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Prior Years 37 6 Increases Related to Tax Positions for Current Year 153 113 Uncertain Positions Resolved During Year (170 ) (186 ) Balance on September 30 $ 1,302 $ 617 The balance of unrecognized tax benefits as of September 30, 2019 September 30, 2019 not September 30, 2019. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of September 30, 2019, no 2016 2015 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
Accounting Policies [Abstract] | |
Revenue [Policy Text Block] | Revenue Recognition 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 customer’s specifications where the terms of the contract require transfer of the completed product. Provisions for sales returns, early payment terms discounts, volume-based variable pricing incentives and warranty costs are recorded as reductions to revenue at the time revenue is recognized based on customer history, historical information and current trends. In addition to recognizing revenue from contracts with customers under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Accounting Standards Update (ASU) No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 980, Reg ul ated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately, or jointly with other transmission service providers, under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP has recovered costs and earned incentives or returns on investments subject to recovery under several ARP rate riders, including: ● In Minnesota: Transmission Cost Recovery (TCR), Environmental Cost Recovery (ECR), Renewable Resource Adjustment (RRA), Energy Intensive Trade Exposed and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR, Phase-in Rate Plan and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers net of amounts billed that are subject to refund through future rider adjustments. Amounts accrued and subject to recovery through future rider rate updates and adjustments are reported as changes in accrued revenues under ARPs on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three nine September 30, 2019 2018. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three nine September 30, 2019 2018. |
Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block] | Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 The level 2 third may |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 September 30, 2019 |
Inventory, Policy [Policy Text Block] | Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270 |
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, 2018 not The following table indicates there were no changes to goodwill by business segment during the first nine 2019: (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at September 30, 2019 December 31, 2018: September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 The amortization expense for these intangible assets was: Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099 |
Cash Flow Supplemental [Policy Text Block] | Supplemental Disclosures of Cash Flow Information As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059 |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Standards Adopted ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 2016 02 December 15, 2018, 842 2016 02 January 1, 2019. 8 ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income 220 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2018 02 December 15, 2018, 2018 02 The Company adopted the updates in ASU 2018 02 January 1, 2019, not Support for the determination of the stranded tax effects resulting from the enactment of the TCJA in AOCI/(L) is provided in the table below. (in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 ) 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. 2017 04 first 2019. no no New Accounting Standards Pending Adoption ASU 2016 13 June 2016 No. 2016 13, Financial Instruments—Credit Losses (Topic 326 326 , may 326 December 15, 2019. not ASU 201 8 - 1 5 August 2018 No. 2018 15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350 40 , 350 40, Internal-Use Software 2018 15 2018 15 350 40 2018 15 2018 15 December 15, 2019 2018 15 first 2020 no |
Note 1 - Summary of Significa_2
Note 1 - Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | September 30 , 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,462 Corporate Debt Securities – Held by Captive Insurance Company $ 3,378 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,772 Other Assets: Money Market and Mutual Funds – Retirement Plans 2,661 Total Assets $ 4,123 $ 8,150 December 31, 201 8 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,294 Corporate Debt Securities – Held by Captive Insurance Company $ 5,898 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,586 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 838 Total Assets $ 2,132 $ 7,484 |
Schedule of Inventory, Current [Table Text Block] | September 30, December 31, (in thousands) 2019 2018 Finished Goods $ 29,601 $ 37,130 Work in Process 18,884 20,393 Raw Material, Fuel and Supplies 48,567 48,747 Total Inventories $ 97,052 $ 106,270 |
Schedule of Goodwill [Table Text Block] | (in thousands) Gross Balance December 31, 2018 Accumulated Impairments Balance (net of impairments) December 31, 2018 Adjustments to Goodwill in 2019 Balance (net of impairments) September 30, 2019 Manufacturing $ 18,270 $ - $ 18,270 $ - $ 18,270 Plastics 19,302 - 19,302 - 19,302 Total $ 37,572 $ - $ 37,572 $ - $ 37,572 |
Schedule of Finite-Lived Intangible Assets [Table Text Block] | September 30 , 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,976 $ 11,515 3 - 191 Other 154 107 47 11 Total $ 22,645 $ 11,083 $ 11,562 December 31, 201 8 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,127 $ 12,364 12 - 200 Other 154 68 86 20 Total $ 22,645 $ 10,195 $ 12,450 |
Finite-lived Intangible Assets Amortization Expense [Table Text Block] | Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 329 $ 888 $ 1,019 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] | (in thousands) 2019 2020 2021 2022 2023 Estimated Amortization Expense – Intangible Assets $ 1,184 $ 1,133 $ 1,099 $ 1,099 $ 1,099 |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | As of September 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 15,893 $ 12,059 |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block] | (in thousands) Unrealized Gains on Available-for- Sale Securities Unamortized Actuarial Losses and Prior Service Costs on Pension and Other Postretirement Benefits AOCI/(L) Balance on December 22, 2017 – Pre-tax $ 71 $ (5,672 ) $ (5,601 ) Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts $ 10 $ (794 ) $ (784 ) |
Note 2 - Segment Information (T
Note 2 - Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 100,345 $ 88,750 $ 303,276 $ 287,330 Changes in Accrued ARP Revenues (921 ) (317 ) (1,601 ) (2,757 ) Total Retail Sales Revenue 99,424 88,433 301,675 284,573 Transmission Services Revenue 11,692 12,569 34,023 35,785 Wholesale Revenues – Company Generation 1,631 2,826 4,099 6,380 Other Revenues 1,626 1,614 4,929 5,394 Total Electric Segment Revenues 114,373 105,442 344,726 332,132 Manufacturing Segment: Metal Parts and Tooling 56,255 55,864 185,520 170,179 Plastic Products and Tooling 8,088 8,790 26,486 26,986 Other 1,379 2,373 5,034 6,678 Total Manufacturing Segment Revenues 65,722 67,027 217,040 203,843 Plastics Segment – Sale of PVC Pipe Products 48,566 55,203 142,100 159,332 Intersegment Eliminations (9 ) (10 ) (39 ) (31 ) Total $ 228,652 $ 227,662 $ 703,827 $ 695,276 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,300 $ 6,509 $ 19,566 $ 19,586 Manufacturing 561 555 1,791 1,664 Plastics 197 150 561 460 Corporate and Intersegment Eliminations 481 335 1,272 887 Total $ 7,539 $ 7,549 $ 23,190 $ 22,597 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 4,066 $ 5,172 $ 9,874 $ 7,881 Manufacturing 285 799 2,888 3,040 Plastics 1,914 2,276 5,287 6,897 Corporate (1,329 ) (888 ) (4,142 ) (3,611 ) Total $ 4,936 $ 7,359 $ 13,907 $ 14,207 Three Months Ended Nine Months Ended September 30, September 30, (in thousands) 2019 2018 2019 2018 Electric $ 17,682 $ 14,567 $ 43,884 $ 41,835 Manufacturing 3,155 3,022 11,987 10,769 Plastics 5,397 6,432 14,918 19,505 Corporate (1,489 ) (748 ) (4,294 ) (3,925 ) Total $ 24,745 $ 23,273 $ 66,495 $ 68,184 September 30, December 31, (in thousands) 2019 2018 Electric $ 1,829,271 $ 1,728,534 Manufacturing 206,835 187,556 Plastics 97,459 91,630 Corporate 46,626 44,797 Total $ 2,180,191 $ 2,052,517 |
Note 3 - Rate and Regulatory _2
Note 3 - Rate and Regulatory Matters (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Revenues Recorded under Rate Riders [Table Text Block] | Three Months Ended September 30, Nine Months Ended September 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives $ 1,518 $ 1,488 $ 4,246 $ 4,300 Renewable Resource Recovery 1,316 817 3,949 2,001 Transmission Cost Recovery (284 ) (1,196 ) 301 (1,683 ) Environmental Cost Recovery - 24 (1 ) (25 ) North Dakota Transmission Cost Recovery 908 1,922 3,554 5,149 Renewable Resource Adjustment (20 ) 2,220 616 6,266 Generation Cost Recovery 137 - 607 - Environmental Cost Recovery (7 ) 1,823 556 5,474 South Dakota Transmission Cost Recovery 743 496 1,587 1,282 Conservation Improvement Program Costs and Incentives 100 238 440 589 Phase-In Rate Plan Recovery (10 ) - (10 ) - Environmental Cost Recovery (2 ) 545 (29 ) 1,580 Total $ 4,399 $ 8,377 $ 15,816 $ 24,933 |
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 2018 Incentive and Cost Recovery A – October 24, 2019 December 1, 2019 $ 11,926 $0.00710 /kwh 2017 Incentive and Cost Recovery A – October 4, 2018 November 1, 2018 $ 10,283 $0.00600 /kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536 /kwh Transmission Cost Recovery 2018 Annual Update–Scenario A R – November 30, 2018 June 1, 2019 $ 6,475 Various –Scenario B $ 2,708 Various 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (3,311 ) Various Environmental Cost Recovery 2018 Annual Update A – November 29, 2018 December 1, 2018 $ - 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base Renewable Resource Adjustment 2019 Annual Update – Revised R – September 30, 2019 November 1, 2019 $ 12,506 $0.00467 /kwh 2018 Annual Update A – August 29, 2018 November 1, 2018 $ 5,886 $0.00219 /kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $0.00049 /kwh North Dakota Renewable Resource Adjustment 2019 Annual Update A – May 1, 2019 June 1, 2019 $ (235 ) -0.224% of base 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 Transmission Cost Recovery 2019 Annual Update R – August 30, 2019 January 1, 2020 $ 5,739 Various 2018 Supplemental Update A – December 6, 2018 February 1, 2019 $ 4,801 Various 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 Environmental Cost Recovery 2019 Update A – October 22, 2019 November 1, 2019 $ - 0% of base 2018 Update A – December 19, 2018 February 1, 2019 $ (378 ) -0.310% of base 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 Generation Cost Recovery 2019 Initial Request A – May 15, 2019 July 1, 2019 $ 2,720 2.547% of base South Dakota Transmission Cost Recovery 2019 Rate Reset A – September 17, 2019 October 1, 2019 $ 2,046 Various 2019 Annual Update A – February 20, 2019 March 1, 2019 $ 1,638 Various 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ 1,171 Various 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various Environmental Cost Recovery 2018 Interim Rate Reset A – October 18, 2018 October 18, 2018 $ (189 ) -$0.00075 /kwh 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483 /kwh Phase-In Rate Plan Recovery 2019 Initial Request A – August 21, 2019 September 1, 2019 $ 864 3.345% of base |
Note 4 - Regulatory Assets an_2
Note 4 - Regulatory Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | September 30, 2019 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,355 $ 113,657 $ 120,012 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,571 7,571 asset lives Conservation Improvement Program Costs and Incentives 2 243 5,339 5,582 24 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,856 - 2,856 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,525 1,525 asset lives Deferred Marked-to-Market Losses 1 972 186 1,158 15 Big Stone II Unrecovered Project Costs – Minnesota 1 706 409 1,115 19 Debt Reacquisition Premiums 1 203 598 801 156 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 60 711 771 27 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 418 - 418 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 234 350 36 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 339 - 339 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 270 270 see below South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 193 - 193 5 Recoverable Fuel and Purchased Power Costs – South Dakota 1 124 - 124 12 North Dakota Generation Cost Recovery Rider Accrued Revenues 2 78 - 78 9 Deferred Lease Expenses 1 - 51 51 42 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 3 Total Regulatory Assets $ 12,667 $ 130,551 $ 143,218 Regulatory Liabilities: Deferred Income Taxes $ - $ 141,337 $ 141,337 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 96,981 96,981 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 3,836 - 3,836 3 North Dakota Renewable Resource Recovery Rider Accrued Refund 684 - 684 8 North Dakota Transmission Cost Recovery Rider Accrued Refund 601 - 601 2 North Dakota Environmental Cost Recovery Rider Accrued Refund 537 - 537 2 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 342 342 see below Refundable Fuel Clause Adjustment Revenues – North Dakota 305 - 305 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 140 47 187 15 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 151 - 151 12 South Dakota Phase-In Rate Plan Rider Accrued Refund 39 - 39 12 Minnesota Renewable Resource Recovery Rider Accrued Refund 12 - 12 12 Other 6 74 80 171 Total Regulatory Liabilities $ 6,311 $ 238,781 $ 245,092 Net Regulatory Asset/(Liability) Position $ 6,356 $ (108,230 ) $ (101,874 ) December 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 $ 6,346 $ 118,433 $ 124,779 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,169 7,169 asset lives Conservation Improvement Program Costs and Incentives 2 5,995 3,285 9,280 21 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 444 - 444 12 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 178 - 178 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 342 442 53 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 Deferred Income Taxes 1 - 2,423 2,423 asset lives Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 452 - 452 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 328 - 328 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 17 - 17 12 Total Regulatory Assets $ 17,225 $ 135,257 $ 152,482 Regulatory Liabilities: Deferred Income Taxes $ - $ 142,779 $ 142,779 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,229 83,229 asset lives Refundable Fuel Clause Adjustment Revenues 121 - 121 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 177 - 177 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 60 - 60 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 166 166 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up - 187 187 24 South Dakota Transmission Cost Recovery Rider Accrued Refund 168 - 168 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 207 - 207 12 Other 5 108 113 180 Total Regulatory Liabilities $ 738 $ 226,469 $ 227,207 Net Regulatory Asset/(Liability) Position $ 16,487 $ (91,212 ) $ (74,725 ) |
Note 5 - Common Shares and Ea_2
Note 5 - Common Shares and Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Common Stock Outstanding Roll Forward [Table Text Block] | Common Shares Outstanding, December 31, 2018 39,664,884 Issuances: Executive Stock Performance Awards (2016 shares earned) 102,198 Vesting of Restricted Stock Units 27,125 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, September 30, 2019 39,755,277 |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Three Months ended September 30, Nine Months ended September 30, 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,714,672 39,621,524 39,694,677 39,592,705 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 149,023 206,268 147,106 210,691 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 68,138 58,680 63,902 58,475 Nonvested Restricted Shares 13,107 14,761 14,896 17,712 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,799 2,332 1,999 2,522 Total Dilutive Shares 232,067 282,041 227,903 289,400 Weighted Average Common Shares Outstanding – Diluted 39,946,739 39,903,565 39,922,580 39,882,105 |
Note 6 - Share-based Payments (
Note 6 - Share-based Payments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block] | Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted: Under Executive and Select Employee Agreements February 13, 2019 47,800 $ 42.875 December 31, 2021 Under Legacy Agreement February 13, 2019 7,800 $ 45.885 December 31, 2021 Restricted Stock Units Granted to Executive Officers February 13, 2019 15,600 $ 49.6225 25% per year through February 6, 2023 Restricted Stock Units Granted to Key Employees April 8, 2019 13,270 $ 44.45 100% on April 8, 2023 Restricted Stock Granted to Nonemployee Directors April 8, 2019 15,700 $ 49.73 33% per year through April 8, 2022 |
Share-based Payment Arrangement, Activity [Table Text Block] | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 743 $ 718 $ 3,274 $ 2,037 Restricted Stock Units Granted to Executive Officers 189 174 999 596 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 203 165 572 496 Restricted Stock Units Granted to Key Employees 112 92 346 257 ESPP (15% discount) 54 - 54 - Totals $ 1,301 $ 1,149 $ 5,245 $ 3,402 |
Note 8 - Leases (Tables)
Note 8 - Leases (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Leases, Right-of-use Assets and Lease Liabilities By Business Segment [Table Text Block] | (in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,557 $ 19,967 $ 666 $ 769 $ 24,959 Accumulated Amortization (778 ) (1,836 ) (294 ) (98 ) (3,006 ) Net of Accumulated Amortization $ 2,779 $ 18,131 $ 372 $ 671 $ 21,953 Obligations: Current Operating Lease Liabilities $ 985 $ 2,541 $ 326 $ 154 $ 4,006 Long-Term Operating Lease Liabilities 2,081 15,686 45 572 18,384 Total Lease Liabilities $ 3,066 $ 18,227 $ 371 $ 726 $ 22,390 |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | (in thousands) Right-of-Use Operating Leases OTP Nonelectric Total 2019 $ 275 $ 1,029 $ 1,304 2020 1,115 3,883 4,998 2021 1,100 3,619 4,719 2022 206 3,491 3,697 2023 196 3,203 3,399 Beyond 2023 448 7,979 8,427 Total Minimum Obligations $ 3,340 $ 23,204 $ 26,544 Interest Component of Obligations (274 ) (3,880 ) (4,154 ) Present Value of Minimum Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 |
Lessee, Operating Lease, Lease Obligation Activity [Table Text Block] | (in thousands) OTP Nonelectric Total Operating Lease Obligations, January 1, 2019 $ 3,609 $ 16,760 $ 20,369 Non-cash Acquisition of Right-of-Use Assets 177 5,115 5,292 Lease Modifications - (164 ) (164 ) Lease Obligation Payments (845 ) (3,086 ) (3,931 ) Interest Component of Lease Obligation Payment 125 699 824 Operating Lease Obligations, September 30, 2019 $ 3,066 $ 19,324 $ 22,390 |
Lease, Cost [Table Text Block] | Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating Lease Cost Variable Lease Cost Total Lease Cost Operating Lease Cost Variable Lease Cost Total Lease Cost Plant in Service or CWIP $ 9 $ - $ 9 $ 29 $ - $ 29 Inventory 244 - 244 707 - 707 Cost of Products Sold 963 65 1,028 2,942 137 3,079 Electric Operation and Maintenance Expenses 64 - 64 194 - 194 Other Nonelectric Expenses 51 (1 ) 50 156 - 156 Total $ 1,331 $ 64 $ 1,395 $ 4,028 $ 137 $ 4,165 |
Note 10 - Short-term and Long_2
Note 10 - Short-term and Long-term Borrowings (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Line of Credit Facilities [Table Text Block] | (in thousands) Line Limit In Use on September 30, 2019 Restricted due to Outstanding Letters of Credit Available on September 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 35,837 $ - $ 94,163 $ 120,785 OTP Credit Agreement 170,000 73,160 16,561 80,279 160,316 Total $ 300,000 $ 108,997 $ 16,561 $ 174,442 $ 281,101 |
Schedule of Debt [Table Text Block] | September 30, 2019 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 73,160 $ 35,837 $ 108,997 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 PACE Note, 2.54%, due March 18, 2021 394 394 Total $ 512,000 $ 80,394 $ 592,394 Less: Current Maturities net of Unamortized Debt Issuance Costs - 180 180 Unamortized Long-Term Debt Issuance Costs 1,830 369 2,199 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,170 $ 79,845 $ 590,015 Total Short-Term and Long-Term Debt (with current maturities) $ 583,330 $ 115,862 $ 699,192 December 31, 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 9,384 $ 9,215 $ 18,599 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 PACE Note, 2.54%, due March 18, 2021 523 523 Total $ 512,000 $ 80,523 $ 592,523 Less: Current Maturities net of Unamortized Debt Issuance Costs - 172 172 Unamortized Long-Term Debt Issuance Costs 1,942 407 2,349 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,058 $ 79,944 $ 590,002 Total Short-Term and Long-Term Debt (with current maturities) $ 519,442 $ 89,331 $ 608,773 |
Note 11 - Pension Plan and Ot_2
Note 11 - Pension Plan and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Net Benefit Costs [Table Text Block] | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 $ 4,119 $ 4,845 Interest Cost on Projected Benefit Obligation 3,603 3,363 10,809 10,089 Expected Return on Assets (5,324 ) (5,300 ) (15,973 ) (15,899 ) Amortization of Prior-Service Cost: From Regulatory Asset 1 4 4 12 From Other Comprehensive Income 1 2 - 6 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,163 1,784 3,488 5,351 From Other Comprehensive Income 1 26 46 79 137 Net Periodic Pension Cost 2 $ 844 $ 1,512 $ 2,532 $ 4,535 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in n onservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 ) Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 313 $ 300 Interest Cost on Projected Benefit Obligation 433 399 1,301 1,197 Amortization of Prior-Service Cost: From Regulatory Asset 2 4 4 12 From Other Comprehensive Income 1 4 10 12 29 Amortization of Net Actuarial Loss: From Regulatory Asset 31 66 93 200 From Other Comprehensive Income 1 87 166 262 496 Net Periodic Pension Cost 2 $ 661 $ 745 $ 1,985 $ 2,234 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in n onservice cost components of postretirement benefits 557 645 1,672 1,934 Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 321 $ 382 $ 964 $ 1,145 Interest Cost on Projected Benefit Obligation 770 646 2,312 1,937 Amortization of Net Actuarial Loss: From Regulatory Asset 393 412 1,178 1,236 From Other Comprehensive Income 1 10 11 29 32 Net Periodic Postretirement Benefit Cost 2 $ 1,494 $ 1,451 $ 4,483 $ 4,350 Effect of Medicare Part D Subsidy $ (45 ) $ (37 ) $ (134 ) $ (110 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in n onservice cost components of postretirement benefits 889 768 2,614 2,436 |
Note 12 - Fair Value of Finan_2
Note 12 - Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Fair Value, by Balance Sheet Grouping [Table Text Block] | September 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 921 $ 921 $ 861 $ 861 Short-Term Debt (108,997 ) (108,997 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,195 ) (663,761 ) (590,174 ) (601,513 ) |
Note 14 - Income Tax Expense (T
Note 14 - Income Tax Expense (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Notes Tables | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Three Months Ended September 30, Nine Months Ended September 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 29,681 $ 30,632 $ 80,402 $ 82,391 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 7,717 $ 7,964 $ 20,905 $ 21,422 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (933 ) (838 ) (2,690 ) (2,932 ) Research and Development Tax Credits (612 ) (202 ) (987 ) (562 ) Excess Tax Deduction – Equity Method Stock Awards - (73 ) (827 ) (698 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (774 ) (774 ) Reconciliation and Prior Period Adjustments (688 ) 2,109 (722 ) 2,028 Corporate Owned Life Insurance (50 ) (332 ) (609 ) (360 ) Allowance for Funds Used During Construction – Equity (239 ) (138 ) (419 ) (416 ) Federal Production Tax Credits - (707 ) - (2,757 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (1 ) (166 ) 30 (213 ) Income Tax Expense $ 4,936 $ 7,359 $ 13,907 $ 14,207 Effective Income Tax Rate 16.6 % 24.0 % 17.3 % 17.2 % |
Summary of Income Tax Contingencies [Table Text Block] | (in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Increases Related to Tax Positions for Prior Years 37 6 Increases Related to Tax Positions for Current Year 153 113 Uncertain Positions Resolved During Year (170 ) (186 ) Balance on September 30 $ 1,302 $ 617 |
Note 1 - Summary of Significa_3
Note 1 - Summary of Significant Accounting Policies (Details Textual) - USD ($) | Jan. 01, 2019 | Sep. 30, 2019 | Dec. 31, 2018 |
Goodwill, Impairment Loss | $ 0 | ||
Goodwill, Period Increase (Decrease), Total | $ 0 | ||
Accounting Standards Update 2018-02 [Member] | |||
Tax Cuts and Jobs Act, Reclassification of Stranded Tax Effect From AOCI to Retained Earnings | $ 784,000 | ||
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 | $ 51,300,000 | ||
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage | 35.00% |
Note 1 - Summary of Significa_4
Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Assets | $ 4,123 | $ 2,132 |
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | ||
Investments | 1,462 | 1,294 |
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member] | ||
Other Assets | 2,661 | 838 |
Fair Value, Inputs, Level 2 [Member] | ||
Total Assets | 8,150 | 7,484 |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | ||
Investments | 3,378 | 5,898 |
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Investments | $ 4,772 | $ 1,586 |
Note 1 - Summary of Significa_5
Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Finished Goods | $ 29,601 | $ 37,130 |
Work in Process | 18,884 | 20,393 |
Raw Material, Fuel and Supplies | 48,567 | 48,747 |
Total Inventories | $ 97,052 | $ 106,270 |
Note 1 - Summary of Significa_6
Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Dec. 31, 2018 | |
Gross Balance | $ 37,572 | |
Accumulated Impairments | 0 | |
Balance | $ 37,572 | 37,572 |
Adjustments to Goodwill | 0 | |
Manufacturing [Member] | ||
Gross Balance | 18,270 | |
Accumulated Impairments | 0 | |
Balance | 18,270 | 18,270 |
Adjustments to Goodwill | 0 | |
Plastics [Member] | ||
Gross Balance | 19,302 | |
Accumulated Impairments | 0 | |
Balance | 19,302 | $ 19,302 |
Adjustments to Goodwill | $ 0 |
Note 1 - Summary of Significa_7
Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended |
Sep. 30, 2019 | Dec. 31, 2018 | |
Gross Carrying Amount | $ 22,645 | $ 22,645 |
Accumulated Amortization | 11,083 | 10,195 |
Net Carrying Amount | 11,562 | 12,450 |
Customer Relationships [Member] | ||
Gross Carrying Amount | 22,491 | 22,491 |
Accumulated Amortization | 10,976 | 10,127 |
Net Carrying Amount | $ 11,515 | $ 12,364 |
Customer Relationships [Member] | Minimum [Member] | ||
Remaining Amortization Periods (Month) | 3 months | 12 months |
Customer Relationships [Member] | Maximum [Member] | ||
Remaining Amortization Periods (Month) | 191 months | 200 months |
Other Intangible Assets [Member] | ||
Gross Carrying Amount | $ 154 | $ 154 |
Accumulated Amortization | 107 | 68 |
Net Carrying Amount | $ 47 | $ 86 |
Remaining Amortization Periods (Month) | 11 months | 20 months |
Note 1 - Summary of Significa_8
Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Amortization Expense – Intangible Assets | $ 296 | $ 329 | $ 888 | $ 1,019 |
Note 1 - Summary of Significa_9
Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands | Sep. 30, 2019USD ($) |
2019 | $ 1,184 |
2020 | 1,133 |
2021 | 1,099 |
2022 | 1,099 |
2023 | $ 1,099 |
Note 1 - Summary of Signific_10
Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Sep. 30, 2018 |
Transactions Related to Capital Additions not Settled in Cash | $ 15,893 | $ 12,059 |
Note 1 - Summary of Signific_11
Note 1 - Summary of Significant Accounting Policies - Effect of Stranded Tax Effect (Details) - USD ($) $ in Thousands | Jan. 01, 2019 | Dec. 22, 2017 | Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 |
Other Comprehensive Income (Loss) | $ 119 | $ 164 | $ 432 | $ (176) | ||
AOCI, Accumulated Gain (Loss), Debt Securities, Available-for-sale, Parent [Member] | ||||||
Other Comprehensive Income (Loss) | $ 71 | |||||
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts | $ 10 | |||||
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member] | ||||||
Other Comprehensive Income (Loss) | (5,672) | |||||
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts | (794) | |||||
AOCI Attributable to Parent [Member] | ||||||
Other Comprehensive Income (Loss) | $ (5,601) | $ 119 | $ 164 | 432 | $ (176) | |
Effect of TCJA 14% Federal Tax Rate Reduction on Gross Deferred Tax Amounts | $ (784) | $ (784) |
Note 2 - Segment Information (D
Note 2 - Segment Information (Details Textual) | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Number of Reportable Segments | 3 | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | |||||
Number of Customers | 0 | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Electric [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 11.20% | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | |||||
Number of Customers | 5 | ||||
Concentration Risk, Percentage | 52.00% | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 22.20% | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 11.20% | ||||
Revenue, Segment Benchmark [Member] | Customer Concentration Risk [Member] | Plastics [Member] | |||||
Number of Customers | 2 | ||||
Concentration Risk, Percentage | 39.10% | ||||
Revenue Benchmark [Member] | UNITED STATES | |||||
Concentration Risk, Percentage | 98.50% | 98.10% | 98.70% | 98.20% |
Note 2 - Business Segment Infor
Note 2 - Business Segment Information - Business Segments (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Total Operating Revenues | $ 228,652 | $ 227,662 | $ 703,827 | $ 695,276 | |
Interest charges | 7,539 | 7,549 | 23,190 | 22,597 | |
Income Tax Expense | 4,936 | 7,359 | 13,907 | 14,207 | |
Net Income (Loss) | 24,745 | 23,273 | 66,495 | 68,184 | |
Assets | 2,180,191 | 2,180,191 | $ 2,052,517 | ||
Operating Segments [Member] | Electric [Member] | |||||
Regulated operating revenues | 114,373 | 105,442 | 344,726 | 332,132 | |
Interest charges | 6,300 | 6,509 | 19,566 | 19,586 | |
Income Tax Expense | 4,066 | 5,172 | 9,874 | 7,881 | |
Net Income (Loss) | 17,682 | 14,567 | 43,884 | 41,835 | |
Assets | 1,829,271 | 1,829,271 | 1,728,534 | ||
Operating Segments [Member] | Electric [Member] | Retail [Member] | |||||
Revenue from Contracts with Customers | 100,345 | 88,750 | 303,276 | 287,330 | |
Changes in Accrued ARP Revenues | (921) | (317) | (1,601) | (2,757) | |
Regulated operating revenues | 99,424 | 88,433 | 301,675 | 284,573 | |
Operating Segments [Member] | Electric [Member] | Electric Transmission [Member] | |||||
Revenue from Contracts with Customers | 11,692 | 12,569 | 34,023 | 35,785 | |
Operating Segments [Member] | Electric [Member] | Wholesale [Member] | |||||
Revenue from Contracts with Customers | 1,631 | 2,826 | 4,099 | 6,380 | |
Operating Segments [Member] | Electric [Member] | Product and Service, Other [Member] | |||||
Revenue from Contracts with Customers | 1,626 | 1,614 | 4,929 | 5,394 | |
Operating Segments [Member] | Manufacturing [Member] | |||||
Revenue from Contracts with Customers | 65,722 | 67,027 | 217,040 | 203,843 | |
Interest charges | 561 | 555 | 1,791 | 1,664 | |
Income Tax Expense | 285 | 799 | 2,888 | 3,040 | |
Net Income (Loss) | 3,155 | 3,022 | 11,987 | 10,769 | |
Assets | 206,835 | 206,835 | 187,556 | ||
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member] | |||||
Revenue from Contracts with Customers | 56,255 | 55,864 | 185,520 | 170,179 | |
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member] | |||||
Revenue from Contracts with Customers | 8,088 | 8,790 | 26,486 | 26,986 | |
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member] | |||||
Revenue from Contracts with Customers | 1,379 | 2,373 | 5,034 | 6,678 | |
Operating Segments [Member] | Plastics [Member] | |||||
Revenue from Contracts with Customers | 48,566 | 55,203 | 142,100 | 159,332 | |
Interest charges | 197 | 150 | 561 | 460 | |
Income Tax Expense | 1,914 | 2,276 | 5,287 | 6,897 | |
Net Income (Loss) | 5,397 | 6,432 | 14,918 | 19,505 | |
Assets | 97,459 | 97,459 | 91,630 | ||
Corporate and Eliminations [Member] | |||||
Interest charges | 481 | 335 | 1,272 | 887 | |
Income Tax Expense | (1,329) | (888) | (4,142) | (3,611) | |
Net Income (Loss) | (1,489) | (748) | (4,294) | (3,925) | |
Assets | 46,626 | 46,626 | $ 44,797 | ||
Intersegment Eliminations [Member] | |||||
Regulated operating revenues | $ (9) | $ (10) | $ (39) | $ (31) |
Note 3 - Rate and Regulatory _3
Note 3 - Rate and Regulatory Matters (Details Textual) | Nov. 01, 2019 | Aug. 30, 2019USD ($) | Jun. 28, 2019USD ($) | Jun. 24, 2019USD ($) | Jun. 16, 2019USD ($) | Jun. 11, 2019USD ($) | May 30, 2019USD ($) | Apr. 01, 2019USD ($) | Dec. 01, 2018 | Oct. 16, 2018 | Sep. 26, 2018USD ($) | Apr. 20, 2018USD ($) | Mar. 23, 2018USD ($) | Mar. 22, 2018USD ($) | Nov. 16, 2016USD ($) | Sep. 28, 2016 | May 25, 2016 | Feb. 12, 2015 | Nov. 06, 2014 | Nov. 12, 2013 | Jun. 30, 2016 | Dec. 22, 2015 | Sep. 30, 2019USD ($) | Mar. 31, 2019USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017 | Oct. 24, 2019USD ($) | Mar. 01, 2018USD ($) | Dec. 20, 2017USD ($) | Nov. 02, 2017USD ($) | May 01, 2017 | Dec. 31, 2016USD ($) |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | |||||||||||||||||||||||||||||||
Regulatory Liabilities, Total | $ 245,092,000 | $ 245,092,000 | $ 227,207,000 | ||||||||||||||||||||||||||||||
Minnesota1 [Member] | |||||||||||||||||||||||||||||||||
Effect of Tax Cuts and Jobs Act, Refund to Customers | 11,500,000 | ||||||||||||||||||||||||||||||||
NORTH DAKOTA | |||||||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | $ 800,000 | ||||||||||||||||||||||||||||||||
Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 200,000 | 200,000 | |||||||||||||||||||||||||||||||
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 | 10.41% | 10.82% | |||||||||||||||||||||||||||||||
Regulatory Liabilities, Total | 1,600,000 | 1,600,000 | $ 2,700,000 | ||||||||||||||||||||||||||||||
Contract with Customer, Refund Liability, Total | 1,600,000 | 1,600,000 | |||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | Maximum [Member] | |||||||||||||||||||||||||||||||||
Proposed Reduced Return on Equity Used in Transmission Rates | 13.08% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 7.5056% | ||||||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 9.41% | ||||||||||||||||||||||||||||||||
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% | ||||||||||||||||||||||||||||||||
Expected Rate of Financial Incentive Reduction | 50.00% | ||||||||||||||||||||||||||||||||
Financial Incentives Recognized During Period | $ 3,000,000 | ||||||||||||||||||||||||||||||||
Financial Incentive Offered to MPUC | $ 4,000,000 | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||
Financial Incentive Request Approved | $ 3,000,000 | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota1 [Member] | |||||||||||||||||||||||||||||||||
Environmental Cost Recovery Rider Rate | 0.00% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | |||||||||||||||||||||||||||||||||
Loss Contingency, Estimate of Possible Loss | 2,600,000 | 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% | ||||||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.30% | ||||||||||||||||||||||||||||||||
General Rate Revenue Increase Requested | $ 12,800,000 | $ 13,100,000 | |||||||||||||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Requested | 8.72% | ||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Decrease in Amount | $ 4,500,000 | ||||||||||||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Amount | $ 8,300,000 | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member] | |||||||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.30% | ||||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 4,600,000 | $ 7,100,000 | $ 13,100,000 | ||||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.10% | 4.80% | |||||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease | $ 6,000,000 | ||||||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform | 4,800,000 | ||||||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform | $ 1,200,000 | ||||||||||||||||||||||||||||||||
Percentage of Requested Allowed Rate of Return on Equity | 9.77% | ||||||||||||||||||||||||||||||||
Equity to Total Capitalization Ratio Basis for Return on Equity | 52.50% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota 1 [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||
Environmental Cost Recovery Rider Rate | 0.00% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member] | |||||||||||||||||||||||||||||||||
Annual Revenue Requesting Recovery | $ 5,700,000 | ||||||||||||||||||||||||||||||||
Number of New Projects Included in Request for Recovery | 7 | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2018 General Rate Case [Member] | |||||||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 8.75% | ||||||||||||||||||||||||||||||||
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% | ||||||||||||||||||||||||||||||||
Contract with Customer, Liability, Revenue Recognized | $ 2,200,000 | $ 1,000,000 | |||||||||||||||||||||||||||||||
Understated Amount of OTP's Electric Transmission Plant in Service | $ 44,000,000 | ||||||||||||||||||||||||||||||||
Annual Revenue Requirement Shortfall Resulted from Understatement | 341,000 | ||||||||||||||||||||||||||||||||
Increase in Non-fuel Annual Revenue Resulted from Increased in General Rate Case | $ 2,600,000 | ||||||||||||||||||||||||||||||||
Increase in Non-fuel Annual Revenue Resulted from Increased in General Rate Case, Percentage | 7.70% | ||||||||||||||||||||||||||||||||
Non-fuel Annual Revenue Increased, Perecenage of Adjusted Requsted Annual Revenue | 69.00% | ||||||||||||||||||||||||||||||||
Adjusted Requested Annual Revenue Increased, Amount | $ 3,700,000 | ||||||||||||||||||||||||||||||||
Adjusted Requested Annual Revenue Increased, Percentage | 11.10% | ||||||||||||||||||||||||||||||||
Authorized Return of Equity | 8.75% | ||||||||||||||||||||||||||||||||
Percentage of Excess Weather-normalized Revenue, Refund to Customer | 50.00% | ||||||||||||||||||||||||||||||||
Maximum ROE, Input for Refund to Customer | 9.50% | ||||||||||||||||||||||||||||||||
Percentage of Any Earnings Above Maximum ROE | 100.00% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||||||||||||
Current Project Cost | $ 106,000,000 | ||||||||||||||||||||||||||||||||
Expanded Capacity of Projects | 345 | ||||||||||||||||||||||||||||||||
Extended Distance of Transmission Line | 162 | ||||||||||||||||||||||||||||||||
Percentage of Assets of Project | 100.00% | ||||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Astoria Station Project [Member] | |||||||||||||||||||||||||||||||||
Expanded Capacity of Projects (MW) | 245 | ||||||||||||||||||||||||||||||||
Current Project Capitalized Cost | $ 36,800,000 | ||||||||||||||||||||||||||||||||
Expected Project Cost | 158,000,000 | 158,000,000 | |||||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Merricourt Project [Member] | EDF [Member] | |||||||||||||||||||||||||||||||||
Expanded Capacity of Projects (MW) | 150 | ||||||||||||||||||||||||||||||||
Expected Project Cost | $ 258,000,000 | 258,000,000 | |||||||||||||||||||||||||||||||
Asset Purchase Agreement, Purchase Price | $ 37,700,000 | $ 37,700,000 | $ 34,700,000 | ||||||||||||||||||||||||||||||
Turnkey Engineering, Procurement and Construction Services Agreement, Costs | $ 200,500,000 | ||||||||||||||||||||||||||||||||
Current Project Cost | $ 54,800,000 |
Note 3 - Rate and Regulatory _4
Note 3 - Rate and Regulatory Matters - Summary of Revenues Recorded Under Rate Riders (Details) - Otter Tail Power Company [Member] - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Revenues recorded under rate riders | $ 4,399 | $ 8,377 | $ 15,816 | $ 24,933 |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | ||||
Revenues recorded under rate riders | 1,518 | 1,488 | 4,246 | 4,300 |
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | ||||
Revenues recorded under rate riders | 1,316 | 817 | 3,949 | 2,001 |
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | (284) | (1,196) | 301 | (1,683) |
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | 0 | 24 | (1) | (25) |
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | ||||
Revenues recorded under rate riders | (20) | 2,220 | 616 | 6,266 |
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | 908 | 1,922 | 3,554 | 5,149 |
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | (7) | 1,823 | 556 | 5,474 |
North Dakota 1 [Member] | Generation Cost Recovery [Member] | ||||
Revenues recorded under rate riders | 137 | 0 | 607 | 0 |
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | ||||
Revenues recorded under rate riders | 100 | 238 | 440 | 589 |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | 743 | 496 | 1,587 | 1,282 |
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Revenues recorded under rate riders | (2) | 545 | (29) | 1,580 |
South Dakota 1 [Member] | Phase-in Rate Plan Recovery [Member] | ||||
Revenues recorded under rate riders | $ (10) | $ 0 | $ (10) | $ 0 |
Note 3 - Rate and Regulatory _5
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 | 9 Months Ended | ||
Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($)kWh | Sep. 30, 2018USD ($) | |
Annual Revenue | $ 4,399 | $ 8,377 | $ 15,816 | $ 24,933 |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | ||||
Annual Revenue | 1,518 | 1,488 | $ 4,246 | 4,300 |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member] | ||||
A - Approval Date | Oct. 24, 2019 | |||
Effective Date Requested or Approved | Dec. 1, 2019 | |||
Annual Revenue | $ 11,926 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00710 | |||
Effective Date Requested or Approved | Dec. 1, 2019 | |||
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member] | ||||
A - Approval Date | Oct. 4, 2018 | |||
Effective Date Requested or Approved | Nov. 1, 2018 | |||
Annual Revenue | $ 10,283 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00600 | |||
Effective Date Requested or Approved | Nov. 1, 2018 | |||
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member] | ||||
A - Approval Date | Sep. 15, 2017 | |||
Effective Date Requested or Approved | Oct. 1, 2017 | |||
Annual Revenue | $ 9,868 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | |||
Effective Date Requested or Approved | Oct. 1, 2017 | |||
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Annual Revenue | (284) | (1,196) | $ 301 | (1,683) |
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member] | ||||
Effective Date Requested or Approved | Jun. 1, 2019 | |||
Annual Revenue | $ 6,475 | |||
R - Request Date | Nov. 30, 2018 | |||
Rate | Various | |||
Effective Date Requested or Approved | Jun. 1, 2019 | |||
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario B [Member] | ||||
Annual Revenue | $ 2,708 | |||
Rate | Various | |||
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||||
A - Approval Date | Oct. 30, 2017 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Annual Revenue | $ (3,311) | |||
Rate | Various | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Annual Revenue | 0 | 24 | $ (1) | (25) |
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||||
A - Approval Date | Oct. 30, 2017 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Annual Revenue | $ (1,943) | |||
Rate of base | (0.935%) | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member] | ||||
A - Approval Date | Nov. 29, 2018 | |||
Effective Date Requested or Approved | Dec. 1, 2018 | |||
Annual Revenue | $ 0 | |||
Rate of base | 0.00% | |||
Effective Date Requested or Approved | Dec. 1, 2018 | |||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | ||||
Annual Revenue | 1,316 | 817 | $ 3,949 | 2,001 |
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||||
A - Approval Date | Oct. 30, 2017 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Annual Revenue | $ 1,279 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00049 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member] | ||||
A - Approval Date | Aug. 29, 2018 | |||
Effective Date Requested or Approved | Nov. 1, 2018 | |||
Annual Revenue | $ 5,886 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00219 | |||
Effective Date Requested or Approved | Nov. 1, 2018 | |||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update - Revised [Member] | ||||
Effective Date Requested or Approved | Nov. 1, 2019 | |||
Annual Revenue | $ 12,506 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00467 | |||
R - Request Date | Sep. 30, 2019 | |||
Effective Date Requested or Approved | Nov. 1, 2019 | |||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Annual Revenue | 908 | 1,922 | $ 3,554 | 5,149 |
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member] | ||||
Effective Date Requested or Approved | Jan. 1, 2020 | |||
Annual Revenue | $ 5,739 | |||
R - Request Date | Aug. 30, 2019 | |||
Rate | Various | |||
Effective Date Requested or Approved | Jan. 1, 2020 | |||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||||
A - Approval Date | Feb. 27, 2018 | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
Annual Revenue | $ 7,469 | |||
Rate | Various | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member] | ||||
A - Approval Date | Dec. 6, 2018 | |||
Effective Date Requested or Approved | Feb. 1, 2019 | |||
Annual Revenue | $ 4,801 | |||
Rate | Various | |||
Effective Date Requested or Approved | Feb. 1, 2019 | |||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||||
A - Approval Date | Nov. 29, 2017 | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
Annual Revenue | $ 7,959 | |||
Rate | Various | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Annual Revenue | (7) | 1,823 | $ 556 | 5,474 |
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||||
A - Approval Date | Dec. 20, 2017 | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
Annual Revenue | $ 8,537 | |||
Rate of base | 6.629% | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member] | ||||
A - Approval Date | Dec. 19, 2018 | |||
Effective Date Requested or Approved | Feb. 1, 2019 | |||
Annual Revenue | $ (378) | |||
Rate of base | (0.31%) | |||
Effective Date Requested or Approved | Feb. 1, 2019 | |||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2019 Annual Update [Member] | ||||
A - Approval Date | Oct. 22, 2019 | |||
Effective Date Requested or Approved | Nov. 1, 2019 | |||
Annual Revenue | $ 0 | |||
Rate of base | 0.00% | |||
Effective Date Requested or Approved | Nov. 1, 2019 | |||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||||
A - Approval Date | Feb. 27, 2018 | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
Annual Revenue | $ 7,718 | |||
Rate of base | 5.593% | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | ||||
Annual Revenue | (20) | 2,220 | $ 616 | 6,266 |
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||||
A - Approval Date | Dec. 20, 2017 | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
Annual Revenue | $ 9,989 | |||
Rate of base | 7.756% | |||
Effective Date Requested or Approved | Jan. 1, 2018 | |||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member] | ||||
A - Approval Date | May 1, 2019 | |||
Effective Date Requested or Approved | Jun. 1, 2019 | |||
Annual Revenue | $ (235) | |||
Rate of base | (0.224%) | |||
Effective Date Requested or Approved | Jun. 1, 2019 | |||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||||
A - Approval Date | Feb. 27, 2018 | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
Annual Revenue | $ 9,650 | |||
Rate of base | 7.493% | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
North Dakota 1 [Member] | Generation Cost Recovery [Member] | ||||
Annual Revenue | 137 | 0 | $ 607 | 0 |
North Dakota 1 [Member] | Generation Cost Recovery [Member] | The 2019 Initial Request [Member] | ||||
A - Approval Date | May 15, 2019 | |||
Effective Date Requested or Approved | Jul. 1, 2019 | |||
Annual Revenue | $ 2,720 | |||
Rate of base | 2.547% | |||
Effective Date Requested or Approved | Jul. 1, 2019 | |||
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | ||||
Annual Revenue | 100 | 238 | $ 440 | 589 |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | ||||
Annual Revenue | 743 | 496 | $ 1,587 | 1,282 |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member] | ||||
A - Approval Date | Feb. 20, 2019 | |||
Effective Date Requested or Approved | Mar. 1, 2019 | |||
Annual Revenue | $ 1,638 | |||
Rate | Various | |||
Effective Date Requested or Approved | Mar. 1, 2019 | |||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||||
A - Approval Date | Feb. 28, 2018 | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
Annual Revenue | $ 1,779 | |||
Rate | Various | |||
Effective Date Requested or Approved | Mar. 1, 2018 | |||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Rate Reset [Member] | ||||
A - Approval Date | Sep. 17, 2019 | |||
Effective Date Requested or Approved | Oct. 1, 2019 | |||
Annual Revenue | $ 2,046 | |||
Rate | Various | |||
Effective Date Requested or Approved | Oct. 1, 2019 | |||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member] | ||||
A - Approval Date | Oct. 18, 2018 | |||
Effective Date Requested or Approved | Oct. 18, 2018 | |||
Annual Revenue | $ 1,171 | |||
Rate | Various | |||
Effective Date Requested or Approved | Oct. 18, 2018 | |||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||||
A - Approval Date | Feb. 17, 2017 | |||
Effective Date Requested or Approved | Mar. 1, 2017 | |||
Annual Revenue | $ 2,053 | |||
Rate | Various | |||
Effective Date Requested or Approved | Mar. 1, 2017 | |||
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | ||||
Annual Revenue | $ (2) | $ 545 | $ (29) | $ 1,580 |
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||||
A - Approval Date | Oct. 13, 2017 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
Annual Revenue | $ 2,082 | |||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00483 | |||
Effective Date Requested or Approved | Nov. 1, 2017 | |||
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member] | ||||
A - Approval Date | Oct. 18, 2018 | |||
Effective Date Requested or Approved | Oct. 18, 2018 | |||
Annual Revenue | $ (189) | |||
Rate rider rate (Kilowatt-Hour) | kWh | (0.00075) | |||
Effective Date Requested or Approved | Oct. 18, 2018 | |||
South Dakota 1 [Member] | Phase-In Rate Plan [Member] | The 2019 Initial Request [Member] | ||||
A - Approval Date | Aug. 21, 2019 | |||
Effective Date Requested or Approved | Sep. 1, 2019 | |||
Annual Revenue | $ 864 | |||
Rate of base | 3.345% | |||
Effective Date Requested or Approved | Sep. 1, 2019 |
Note 4 - Regulatory Assets an_3
Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2019 | Dec. 31, 2018 | ||
Regulatory Assets - Current | $ 12,667 | $ 17,225 | |
Regulatory Assets - Long -Term | 130,551 | 135,257 | |
Regulatory Assets - Total | 143,218 | 152,482 | |
Regulatory Liabilities - Current | 6,311 | 738 | |
Regulatory Liabilities - Long -Term | 238,781 | 226,469 | |
Regulatory Liabilities, Total | 245,092 | 227,207 | |
Net Regulatory Asset Position - Current | 6,356 | 16,487 | |
Net Regulatory Asset Position - Long-Term | (108,230) | (91,212) | |
Net Regulatory Asset/(Liability) Position | (101,874) | (74,725) | |
Deferred Income Taxes [Member] | |||
Regulatory Liabilities - Current | 0 | 0 | |
Regulatory Liabilities - Long -Term | 141,337 | 142,779 | |
Regulatory Liabilities, Total | $ 141,337 | $ 142,779 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member] | |||
Regulatory Liabilities - Current | $ 0 | $ 0 | |
Regulatory Liabilities - Long -Term | 96,981 | 83,229 | |
Regulatory Liabilities, Total | $ 96,981 | $ 83,229 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Refundable Fuel Clause Adjustment Revenues - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 3,836 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 3,836 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 3 months | ||
Refundable Fuel Clause Adjustment Revenues [Member] | |||
Regulatory Liabilities - Current | $ 121 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 121 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 684 | $ 177 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 684 | $ 177 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 8 months | 12 months | |
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 601 | $ 60 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 601 | $ 60 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 2 months | 12 months | |
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 537 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 537 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 2 months | ||
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 0 | $ 0 | |
Regulatory Liabilities - Long -Term | 342 | 166 | |
Regulatory Liabilities, Total | $ 342 | $ 166 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | see below | |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Liabilities - Current | $ 140 | $ 0 | |
Regulatory Liabilities - Long -Term | 47 | 187 | |
Regulatory Liabilities, Total | $ 187 | $ 187 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 15 months | 24 months | |
Refundable Fuel Clause Adjustment Revenues – North Dakota [Member] | |||
Regulatory Liabilities - Current | $ 305 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 305 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 168 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 168 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 207 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 207 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 151 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 151 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
Other [Member] | |||
Regulatory Liabilities - Current | $ 6 | $ 5 | |
Regulatory Liabilities - Long -Term | 74 | 108 | |
Regulatory Liabilities, Total | $ 80 | $ 113 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 171 months | 180 months | |
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member] | |||
Regulatory Assets - Current | [1] | $ 6,355 | $ 6,346 |
Regulatory Assets - Long -Term | [1] | 113,657 | 118,433 |
Regulatory Assets - Total | [1] | $ 120,012 | $ 124,779 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
Accumulated ARO Accretion/Depreciation Adjustment [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | $ 0 |
Regulatory Assets - Long -Term | [1] | 7,571 | 7,169 |
Regulatory Assets - Total | [1] | $ 7,571 | $ 7,169 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Conservation Improvement Program Costs and Incentives [Member] | |||
Regulatory Assets - Current | [2] | $ 243 | $ 5,995 |
Regulatory Assets - Long -Term | [2] | 5,339 | 3,285 |
Regulatory Assets - Total | [2] | $ 5,582 | $ 9,280 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 24 months | 21 months |
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 2,856 | $ 444 |
Regulatory Assets - Long -Term | [2] | 0 | 0 |
Regulatory Assets - Total | [2] | $ 2,856 | $ 444 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | 12 months |
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | $ 0 |
Regulatory Assets - Long -Term | [1] | 1,525 | 986 |
Regulatory Assets - Total | [1] | $ 1,525 | $ 986 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Deferred Marked-to-Market Losses [Member] | |||
Regulatory Assets - Current | [1] | $ 972 | $ 1,661 |
Regulatory Assets - Long -Term | [1] | 186 | 743 |
Regulatory Assets - Total | [1] | $ 1,158 | $ 2,404 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 15 months | 24 months |
Big Stone II Unrecovered Project Costs - Minnesota [Member] | |||
Regulatory Assets - Current | [1] | $ 706 | $ 681 |
Regulatory Assets - Long -Term | [1] | 409 | 947 |
Regulatory Assets - Total | [1] | $ 1,115 | $ 1,628 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 19 months | 28 months |
Debt Reacquisition Premiums [Member] | |||
Regulatory Assets - Current | [1] | $ 203 | $ 207 |
Regulatory Assets - Long -Term | [1] | 598 | 753 |
Regulatory Assets - Total | [1] | $ 801 | $ 960 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 156 months | 165 months |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Assets - Current | [1] | $ 60 | $ 240 |
Regulatory Assets - Long -Term | [1] | 711 | 0 |
Regulatory Assets - Total | [1] | $ 771 | $ 240 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 27 months | 12 months |
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 418 | $ 178 |
Regulatory Assets - Long -Term | [1] | 0 | 0 |
Regulatory Assets - Total | [1] | $ 418 | $ 178 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 12 months | 12 months |
Big Stone II Unrecovered Project Costs - South Dakota [Member] | |||
Regulatory Assets - Current | [1] | $ 116 | $ 100 |
Regulatory Assets - Long -Term | [1] | 234 | 342 |
Regulatory Assets - Total | [1] | $ 350 | $ 442 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 36 months | 53 months |
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 339 | $ 455 |
Regulatory Assets - Long -Term | [1] | 0 | 0 |
Regulatory Assets - Total | [1] | $ 339 | $ 455 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 12 months | 12 months |
Minnesota SPP Transmission Cost Recovery Tracker [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | $ 0 |
Regulatory Assets - Long -Term | [1] | 270 | 176 |
Regulatory Assets - Total | [1] | $ 270 | $ 176 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
South Dakota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 193 | |
Regulatory Assets - Long -Term | [2] | 0 | |
Regulatory Assets - Total | [2] | $ 193 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 5 months | |
Minnesota Environmental Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 4 | $ 121 |
Regulatory Assets - Long -Term | [2] | 0 | 0 |
Regulatory Assets - Total | [2] | $ 4 | $ 121 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 3 months | 12 months |
Recoverable Fuel and Purchased Power Costs - South Dakota [Member] | |||
Regulatory Assets - Current | [1] | $ 124 | |
Regulatory Assets - Long -Term | [1] | 0 | |
Regulatory Assets - Total | [1] | $ 124 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 12 months | |
Deferred Income Taxes [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | |
Regulatory Assets - Long -Term | [1] | 2,423 | |
Regulatory Assets - Total | [1] | $ 2,423 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | |
North Dakota Generation Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 78 | |
Regulatory Assets - Long -Term | [2] | 0 | |
Regulatory Assets - Total | [2] | $ 78 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 9 months | |
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 452 | |
Regulatory Assets - Long -Term | [2] | 0 | |
Regulatory Assets - Total | [2] | $ 452 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | |
Deferred Lease Expenses [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | |
Regulatory Assets - Long -Term | [1] | 51 | |
Regulatory Assets - Total | [1] | $ 51 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 42 months | |
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [1] | $ 328 | |
Regulatory Assets - Long -Term | [1] | 0 | |
Regulatory Assets - Total | [1] | $ 328 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 4 months | |
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 17 | |
Regulatory Assets - Long -Term | [2] | 0 | |
Regulatory Assets - Total | [2] | $ 17 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | |
South Dakota Phase-in Rate Plan Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 39 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 39 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 12 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 12 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
[1] | Costs subject to recovery without a rate of return. | ||
[2] | Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Note 5 - Common Shares and Ea_3
Note 5 - Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details) | 9 Months Ended |
Sep. 30, 2019shares | |
Common Shares Outstanding, beginning balance (in shares) | 39,664,884 |
Vesting of Restricted Stock Units (in shares) | 27,125 |
Restricted Stock Issued to Directors (in shares) | 15,700 |
Directors Deferred Compensation (in shares) | 594 |
Shares Withheld for Individual Income Tax Requirements (in shares) | (55,224) |
Common Shares Outstanding, ending balance (in shares) | 39,755,277 |
Performance Awards 2016 [Member] | |
Executive Stock Performance Awards (2016 shares earned) (in shares) | 102,198 |
Note 5 - Common Shares and Ea_4
Note 5 - Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Weighted Average Common Shares Outstanding – Basic (in shares) | 39,714,672 | 39,621,524 | 39,694,677 | 39,592,705 |
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares) | 149,023 | 206,268 | 147,106 | 210,691 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares) | 68,138 | 58,680 | 63,902 | 58,475 |
Nonvested Restricted Shares (in shares) | 13,107 | 14,761 | 14,896 | 17,712 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares) | 1,799 | 2,332 | 1,999 | 2,522 |
Total Dilutive Shares (in shares) | 232,067 | 282,041 | 227,903 | 289,400 |
Weighted Average Common Shares Outstanding – Diluted (in shares) | 39,946,739 | 39,903,565 | 39,922,580 | 39,882,105 |
Note 6 - Share-based Payments_2
Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions | Feb. 13, 2019 | Jul. 31, 2019 | Sep. 30, 2019 |
Employee Stock Purchase Plan, Employee Discount | 15.00% | ||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 4.3 | ||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition | 2 years 1 month 6 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 | 55,600 | ||
Period Specified for Average Adjusted Return | 3 years | ||
Number of Trading Days | 20 days | ||
Number of Shares Authorized for Actual Payment | 83,400 | ||
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 Payment Arrangement, Tranche One [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,800 | ||
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Payment Arrangement, Tranche Two [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,800 |
Note 6 - Share-based Payments -
Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) | 9 Months Ended |
Sep. 30, 2019$ / sharesshares | |
Performance Shares [Member] | The 2014 Stock Incentive Plan [Member] | February 13, 2019 [Member] | |
Shares/units granted (in shares) | shares | 47,800 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 42.875 |
Shares/units granted, vesting date | December 31, 2021 |
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member] | |
Shares/units granted, vesting date | December 31, 2021 |
Performance Shares [Member] | The 2014 Stock Incentive Plan Under Legacy Agreement [Member] | February 13, 2019 [Member] | |
Shares/units granted (in shares) | shares | 7,800 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 45.885 |
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | February 13, 2019 [Member] | Executive Officer [Member] | |
Shares/units granted (in shares) | shares | 15,600 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 49.6225 |
Shares/units granted, vesting date | 25% per year through February 6, 2023 |
Restricted Stock Units (RSUs) [Member] | The 2014 Stock Incentive Plan [Member] | April 8, 2019 [Member] | Key Employee [Member] | |
Shares/units granted (in shares) | shares | 13,270 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 44.45 |
Shares/units granted, vesting date | 100% on April 8, 2023 |
Restricted Stock [Member] | The 2014 Stock Incentive Plan [Member] | April 8, 2019 [Member] | Nonemployee Directors [Member] | |
Shares/units granted (in shares) | shares | 15,700 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 49.73 |
Shares/units granted, vesting date | 33% per year through April 8, 2022 |
Note 6 - Share-based Payments_3
Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) (Parentheticals) - The 2014 Stock Incentive Plan [Member] | 9 Months Ended |
Sep. 30, 2019 | |
Restricted Stock Units (RSUs) [Member] | February 13, 2019 [Member] | Executive Officer [Member] | |
Shares/units granted, vesting percentage | 25.00% |
Restricted Stock Units (RSUs) [Member] | April 8, 2019 [Member] | Key Employee [Member] | |
Shares/units granted, vesting percentage | 100.00% |
Restricted Stock [Member] | April 8, 2019 [Member] | Nonemployee Directors [Member] | |
Shares/units granted, vesting percentage | 33.00% |
Note 6 - Share-based Payments_4
Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Stock compensation expense | $ 1,301 | $ 1,149 | $ 5,245 | $ 3,402 |
Stock Performance Awards [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 743 | 718 | 3,274 | 2,037 |
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 189 | 174 | 999 | 596 |
Restricted Stock Units (RSUs) [Member] | Key Employee [Member] | ||||
Stock compensation expense | 112 | 92 | 346 | 257 |
Restricted Stock [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 0 | 0 | 0 | 16 |
Restricted Stock [Member] | Nonemployee Directors [Member] | ||||
Stock compensation expense | 203 | 165 | 572 | 496 |
Employee Stock Purchase Plan [Member] | ||||
Stock compensation expense | $ 54 | $ 0 | $ 54 | $ 0 |
Note 7 - Retained Earnings an_2
Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($) | Jul. 19, 2019 | Sep. 30, 2019 | Dec. 31, 2018 |
Capitalization, Long-term Debt and Equity, Total | $ 1,346,520,000 | $ 1,318,865,000 | |
Otter Tail Power Company [Member] | |||
Equity to Total Capitalization Ratio | 52.20% | ||
Net Assets Restricted from Distribution | $ 497,000,000 | ||
Capitalization, Long-term Debt and Equity, Total | $ 1,331,302,000 | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Minimum [Member] | |||
Public Utilities, Approved Equity Capital Structure, Percentage | 46.00% | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member] | |||
Public Utilities, Approved Equity Capital Structure, Percentage | 56.20% |
Note 8 - Leases (Details Textua
Note 8 - Leases (Details Textual) - USD ($) $ in Thousands | Sep. 30, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Operating Lease, Right-of-Use Asset | $ 21,953 | $ 0 | |
Operating Lease, Liability, Total | $ 22,390 | $ 20,369 | |
Operating Lease, Weighted Average Remaining Lease Term | 6 years 2 months 12 days | ||
Operating Lease, Weighted Average Discount Rate, Percent | 5.30% | ||
Minimum [Member] | |||
Lessee, Operating Lease, Term of Contract | 1 year | ||
Maximum [Member] | |||
Lessee, Operating Lease, Term of Contract | 10 years | ||
Accounting Standards Update 2016-02 [Member] | |||
Operating Lease, Right-of-Use Asset | $ 20,000 | ||
Operating Lease, Liability, Total | $ 20,000 |
Note 8 - Leases - Lease Assets
Note 8 - Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Gross | $ 24,959 | |
Accumulated Amortization | (3,006) | |
Net of Accumulated Amortization | 21,953 | $ 0 |
Current Operating Lease Liabilities | 4,006 | 0 |
Long-Term Operating Lease Liabilities | 18,384 | 0 |
Total Lease Liabilities | 22,390 | $ 20,369 |
Electric [Member] | ||
Gross | 3,557 | |
Accumulated Amortization | (778) | |
Net of Accumulated Amortization | 2,779 | |
Current Operating Lease Liabilities | 985 | |
Long-Term Operating Lease Liabilities | 2,081 | |
Total Lease Liabilities | 3,066 | |
Manufacturing [Member] | ||
Gross | 19,967 | |
Accumulated Amortization | (1,836) | |
Net of Accumulated Amortization | 18,131 | |
Current Operating Lease Liabilities | 2,541 | |
Long-Term Operating Lease Liabilities | 15,686 | |
Total Lease Liabilities | 18,227 | |
Plastics [Member] | ||
Gross | 666 | |
Accumulated Amortization | (294) | |
Net of Accumulated Amortization | 372 | |
Current Operating Lease Liabilities | 326 | |
Long-Term Operating Lease Liabilities | 45 | |
Total Lease Liabilities | 371 | |
Corporate Segment [Member] | ||
Gross | 769 | |
Accumulated Amortization | (98) | |
Net of Accumulated Amortization | 671 | |
Current Operating Lease Liabilities | 154 | |
Long-Term Operating Lease Liabilities | 572 | |
Total Lease Liabilities | $ 726 |
Note 8 - Leases - Lease Obligat
Note 8 - Leases - Lease Obligations (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
2019 | $ 1,304 | |
2020 | 4,998 | |
2021 | 4,719 | |
2022 | 3,697 | |
2023 | 3,399 | |
Beyond 2023 | 8,427 | |
Total Minimum Obligations | 26,544 | |
Interest Component of Obligations | (4,154) | |
Present Value of Minimum Obligations, September 30, 2019 | 22,390 | $ 20,369 |
OTP [Member] | ||
2019 | 275 | |
2020 | 1,115 | |
2021 | 1,100 | |
2022 | 206 | |
2023 | 196 | |
Beyond 2023 | 448 | |
Total Minimum Obligations | 3,340 | |
Interest Component of Obligations | (274) | |
Present Value of Minimum Obligations, September 30, 2019 | 3,066 | 3,609 |
Nonelectric Companies [Member] | ||
2019 | 1,029 | |
2020 | 3,883 | |
2021 | 3,619 | |
2022 | 3,491 | |
2023 | 3,203 | |
Beyond 2023 | 7,979 | |
Total Minimum Obligations | 23,204 | |
Interest Component of Obligations | (3,880) | |
Present Value of Minimum Obligations, September 30, 2019 | $ 19,324 | $ 16,760 |
Note 8 - Leases - Operating Lea
Note 8 - Leases - Operating Lease Obligation (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Operating Lease Obligations, beginning balance | $ 20,369 |
Non-cash Acquisition of Right-of-Use Assets | 5,292 |
Lease Modifications | (164) |
Lease Obligation Payments | (3,931) |
Interest Component of Lease Obligation Payment | 824 |
Operating Lease Obligations, ending balance | 22,390 |
OTP [Member] | |
Operating Lease Obligations, beginning balance | 3,609 |
Non-cash Acquisition of Right-of-Use Assets | 177 |
Lease Modifications | 0 |
Lease Obligation Payments | (845) |
Interest Component of Lease Obligation Payment | 125 |
Operating Lease Obligations, ending balance | 3,066 |
Nonelectric Companies [Member] | |
Operating Lease Obligations, beginning balance | 16,760 |
Non-cash Acquisition of Right-of-Use Assets | 5,115 |
Lease Modifications | (164) |
Lease Obligation Payments | (3,086) |
Interest Component of Lease Obligation Payment | 699 |
Operating Lease Obligations, ending balance | $ 19,324 |
Note 8 - Leases - Allocation of
Note 8 - Leases - Allocation of Lease Costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Operating lease cost | $ 1,331 | $ 4,028 |
Variable lease cost | 64 | 137 |
Total lease cost | 1,395 | 4,165 |
Fixed Assets [Member] | ||
Operating lease cost | 9 | 29 |
Variable lease cost | 0 | 0 |
Total lease cost | 9 | 29 |
Production Fuel [Member] | ||
Operating lease cost | 244 | 707 |
Variable lease cost | 0 | 0 |
Total lease cost | 244 | 707 |
Cost of Sales [Member] | ||
Operating lease cost | 963 | 2,942 |
Variable lease cost | 65 | 137 |
Total lease cost | 1,028 | 3,079 |
Electric Operating and Maintenance Expenses [Member] | ||
Operating lease cost | 64 | 194 |
Variable lease cost | 0 | 0 |
Total lease cost | 64 | 194 |
Other Nonelectric Expenses [member] | ||
Operating lease cost | 51 | 156 |
Total lease cost | 50 | 156 |
Variable lease cost | $ (1) | $ 0 |
Note 9 - Commitments and Cont_2
Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2019 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2018 | |
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | ||||
Estimated Liability of Refund Obligation | $ 1.6 | |||
Otter Tail Power Company [Member] | Construction Programs [Member] | ||||
Contract Expiration Year | 2021 | 2021 | ||
Long-term Purchase Commitment, Amount | $ 138.9 | $ 64.5 | ||
Increase (Decrease) in Long Term Purchase Commitments | 77.5 | |||
Otter Tail Power Company [Member] | Construction Programs [Member] | Forecast [Member] | ||||
Increase (Decrease) in Long Term Purchase Commitments | $ 9.7 | $ 70.3 | ||
Otter Tail Power Company [Member] | Construction Programs, Unmet Project Commitments [Member] | ||||
Increase (Decrease) in Long Term Purchase Commitments | $ (5.7) | |||
Otter Tail Power Company [Member] | Capacity and Energy Requirements [Member] | ||||
Contract Expiration Year | 2042 | |||
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member] | ||||
Contract Expiration Year | 2040 | |||
Otter Tail Power Company [Member] | Coal Purchase Commitments 3 [Member] | ||||
Contract Expiration Year | 2020 | |||
Otter Tail Power Company [Member] | OTP Land Easements [Member] | ||||
Contract Expiration Year | 2034 | |||
Long-term Purchase Commitment, Amount | $ 10.4 | |||
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member] | ||||
Long-term Purchase Commitment, Amount | 5 | |||
Long-term Purchase Commitment, Estimated Annual Payment | $ 1.6 |
Note 10 - Short-term and Long_3
Note 10 - Short-term and Long-term Borrowings (Details Textual) - USD ($) | Oct. 10, 2019 | Oct. 31, 2019 | Sep. 30, 2019 | Sep. 12, 2019 |
Line of Credit Facility, Maximum Borrowing Capacity | $ 300,000,000 | |||
Otter Tail Corporation Credit Agreement [Member] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | 130,000,000 | |||
Otter Tail Corporation Credit Agreement [Member] | Subsequent Event [Member] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 170,000,000 | |||
Series 2019 Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 175,000,000 | |||
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% | |||
Debt to Total Capitalization Ratio | 60.00% | |||
Priority Debt to Total Capitalization | 20.00% | |||
Series 2019 Notes [Member] | Subsequent Event [Member] | Otter Tail Power Company [Member] | ||||
Proceeds from Notes Payable, Total | $ 100,000,000 | |||
Series 2019A Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 10,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.07% | |||
Series 2019B Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 26,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.52% | |||
Series 2019C Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 64,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.82% | |||
Series 2020A Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 10,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.22% | |||
Series 2020B Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 40,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.22% | |||
Series 2020C Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 10,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.62% | |||
Series 2020D Notes [Member] | Otter Tail Power Company [Member] | ||||
Debt Instrument, Face Amount | $ 15,000,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.92% | |||
OTP Credit Agreement [Member] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 170,000,000 | |||
OTP Credit Agreement [Member] | Subsequent Event [Member] | Otter Tail Power Company [Member] | ||||
Repayments of Debt | $ 69,900,000 |
Note 10 - Short-term and Long_4
Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Line of Credit Facility, Maximum Borrowing Capacity | $ 300,000 | |
In Use | 108,997 | |
Restricted due to Outstanding Letters of Credit | 16,561 | |
Available | 174,442 | $ 281,101 |
Otter Tail Corporation Credit Agreement [Member] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 130,000 | |
In Use | 35,837 | |
Restricted due to Outstanding Letters of Credit | 0 | |
Available | 94,163 | 120,785 |
OTP Credit Agreement [Member] | ||
Line of Credit Facility, Maximum Borrowing Capacity | 170,000 | |
In Use | 73,160 | |
Restricted due to Outstanding Letters of Credit | 16,561 | |
Available | $ 80,279 | $ 160,316 |
Note 10 - Short-term and Long_5
Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Short-Term Debt | $ 108,997 | $ 18,599 |
Long-Term Debt | 592,394 | 592,523 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 180 | 172 |
Unamortized Long-Term Debt Issuance Costs | 2,199 | 2,349 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 590,015 | 590,002 |
Total Short-Term and Long-Term Debt (with current maturities) | 699,192 | 608,773 |
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 | 100,000 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | 394 | 523 |
Otter Tail Power Company [Member] | ||
Short-Term Debt | 73,160 | 9,384 |
Long-Term Debt | 512,000 | 512,000 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 0 | 0 |
Unamortized Long-Term Debt Issuance Costs | 1,830 | 1,942 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 510,170 | 510,058 |
Total Short-Term and Long-Term Debt (with current maturities) | 583,330 | 519,442 |
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 | 100,000 |
Parent Company [Member] | ||
Short-Term Debt | 35,837 | 9,215 |
Long-Term Debt | 80,394 | 80,523 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 180 | 172 |
Unamortized Long-Term Debt Issuance Costs | 369 | 407 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 79,845 | 79,944 |
Total Short-Term and Long-Term Debt (with current maturities) | 115,862 | 89,331 |
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | 80,000 | 80,000 |
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | $ 394 | $ 523 |
Note 10 - Short-term and Long_6
Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals) | 9 Months Ended | 12 Months Ended |
Sep. 30, 2019 | Dec. 31, 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% | 4.07% |
Long-Term Debt, Due Date | Feb. 7, 2048 | Feb. 7, 2048 |
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 11 - Pension Plan and Ot_3
Note 11 - Pension Plan and Other Postretirement Benefits (Details Textual) - USD ($) $ in Millions | 1 Months Ended | |
Sep. 30, 2019 | Jan. 31, 2019 | |
Pension Plan [Member] | ||
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 12.5 | $ 10 |
Note 11 - Pension Plan and Ot_4
Note 11 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | ||
Pension Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | $ 1,373 | $ 1,615 | $ 4,119 | $ 4,845 | |
Interest Cost on Projected Benefit Obligation | 3,603 | 3,363 | 10,809 | 10,089 | |
Expected Return on Assets | (5,324) | (5,300) | (15,973) | (15,899) | |
From Regulatory Asset | 1 | 4 | 4 | 12 | |
From Other Comprehensive Income | [1] | 2 | 0 | 6 | 0 |
From Regulatory Asset | 1,163 | 1,784 | 3,488 | 5,351 | |
From Other Comprehensive Income | [1] | 26 | 46 | 79 | 137 |
Net Periodic Pension Cost | [2] | 844 | 1,512 | 2,532 | 4,535 |
From Other Comprehensive Income | [1] | 26 | 46 | 79 | 137 |
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 333 | 455 | 1,059 | 1,162 | |
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 1,007 | 1,119 | 2,961 | 3,561 | |
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 33 | 41 | 99 | 121 | |
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | (128) | (29) | (408) | (74) | |
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | (401) | (74) | (1,179) | (235) | |
Executive Survivor and Supplemental Retirement Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 104 | 100 | 313 | 300 | |
Interest Cost on Projected Benefit Obligation | 433 | 399 | 1,301 | 1,197 | |
From Regulatory Asset | 2 | 4 | 4 | 12 | |
From Other Comprehensive Income | [3] | 4 | 10 | 12 | 29 |
From Regulatory Asset | 31 | 66 | 93 | 200 | |
From Other Comprehensive Income | [3] | 87 | 166 | 262 | 496 |
Net Periodic Pension Cost | [4] | 661 | 745 | 1,985 | 2,234 |
From Other Comprehensive Income | [3] | 87 | 166 | 262 | 496 |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 26 | 24 | 78 | 74 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 78 | 76 | 235 | 226 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | 557 | 645 | 1,672 | 1,934 | |
Other Postretirement Benefits Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 321 | 382 | 964 | 1,145 | |
Interest Cost on Projected Benefit Obligation | 770 | 646 | 2,312 | 1,937 | |
From Regulatory Asset | 393 | 412 | 1,178 | 1,236 | |
From Other Comprehensive Income | [1] | 10 | 11 | 29 | 32 |
Net Periodic Pension Cost | [5] | 1,494 | 1,451 | 4,483 | 4,350 |
From Other Comprehensive Income | [1] | 10 | 11 | 29 | 32 |
Effect of Medicare Part D Subsidy | (45) | (37) | (134) | (110) | |
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 78 | 108 | 248 | 275 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 235 | 264 | 693 | 841 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 8 | 10 | 23 | 29 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | 284 | 301 | 905 | 769 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | $ 889 | $ 768 | $ 2,614 | $ 2,436 | |
[1] | Corporate cost included in nonservice cost components of postretirement benefits. | ||||
[2] | Allocation of Costs: Costs included in OTP capital expenditures $ 333 $ 455 $ 1,059 $ 1,162 Service costs included in electric operation and maintenance expenses 1,007 1,119 2,961 3,561 Service costs included in other nonelectric expenses 33 41 99 121 Nonservice costs capitalized as regulatory assets (128 ) (29 ) (408 ) (74 ) Nonservice costs included in nonservice cost components of postretirement benefits (401 ) (74 ) (1,179 ) (235 ) | ||||
[3] | Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits. | ||||
[4] | Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 26 $ 24 $ 78 $ 74 Service costs included in other nonelectric expenses 78 76 235 226 Nonservice costs included in nonservice cost components of postretirement benefits 557 645 1,672 1,934 | ||||
[5] | Allocation of Costs: Costs included in OTP capital expenditures $ 78 $ 108 $ 248 $ 275 Service costs included in electric operation and maintenance expenses 235 264 693 841 Service costs included in other nonelectric expenses 8 10 23 29 Nonservice costs capitalized as regulatory assets 284 301 905 769 Nonservice costs included in nonservice cost components of postretirement benefits 889 768 2,614 2,436 |
Note 12 - Fair Value of Finan_3
Note 12 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member] | 9 Months Ended | 12 Months Ended |
Sep. 30, 2019 | Dec. 31, 2018 | |
Otter Tail Corporation Credit Agreement [Member] | ||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | 1.50% |
OTP Credit Agreement [Member] | ||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | 1.25% |
Note 12 - Fair Value of Finan_4
Note 12 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Reported Value Measurement [Member] | ||
Cash and Cash Equivalents | $ 921 | $ 861 |
Short-Term Debt | (108,997) | (18,599) |
Long-Term Debt including Current Maturities | (590,195) | (590,174) |
Estimate of Fair Value Measurement [Member] | ||
Cash and Cash Equivalents | 921 | 861 |
Short-Term Debt | (108,997) | (18,599) |
Long-Term Debt including Current Maturities | $ (663,761) | $ (601,513) |
Note 14 - Income Tax Expense (D
Note 14 - Income Tax Expense (Details Textual) $ in Thousands | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Period for Unrecognized Tax Benefits Not Expected Change | 12 months |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ 0 |
Domestic Tax Authority [Member] | |
Open Tax Year | 2016 2017 2018 |
State and Local Jurisdiction [Member] | Minnesota Department of Revenue [Member] | |
Open Tax Year | 2015 2016 2017 2018 |
Note 14 - Income Tax Expense -
Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Income Before Income Taxes | $ 29,681 | $ 30,632 | $ 80,402 | $ 82,391 |
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | 7,717 | 7,964 | 20,905 | 21,422 |
Differences Reversing in Excess of Federal Rates | (933) | (838) | (2,690) | (2,932) |
Research and Development Tax Credits | (612) | (202) | (987) | (562) |
Excess Tax Deduction – Equity Method Stock Awards | 0 | (73) | (827) | (698) |
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258) | (258) | (774) | (774) |
Reconciliation and Prior Period Adjustments | (688) | 2,109 | (722) | 2,028 |
Corporate Owned Life Insurance | (50) | (332) | (609) | (360) |
Allowance for Funds Used During Construction – Equity | (239) | (138) | (419) | (416) |
Federal Production Tax Credits | 0 | (707) | 0 | (2,757) |
Other Comprehensive Income Deferred Tax Rate Adjustment | 0 | 0 | 0 | (531) |
Other Items – Net | (1) | (166) | 30 | (213) |
Income Tax Expense | $ 4,936 | $ 7,359 | $ 13,907 | $ 14,207 |
Effective Income Tax Rate | 16.60% | 24.00% | 17.30% | 17.20% |
Note 14 - Income Tax Expense _2
Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) (Parentheticals) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Composite Federal and State Statutory Rate | 26.00% | 26.00% | 26.00% | 26.00% |
Note 14 - Income Tax Expense _3
Note 14 - Income Tax Expense - Unrecognized Tax Benefit Activity (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Balance, beginning | $ 1,282 | $ 684 |
Increases Related to Tax Positions for Prior Years | 37 | 6 |
Increases Related to Tax Positions for Current Year | 153 | 113 |
Uncertain Positions Resolved During Year | (170) | (186) |
Balance, ending | $ 1,302 | $ 617 |