Document And Entity Information
Document And Entity Information - shares | 6 Months Ended | |
Jun. 30, 2019 | Jul. 31, 2019 | |
Document Information [Line Items] | ||
Entity Central Index Key | 0001466593 | |
Entity Shell Company | false | |
Entity Registrant Name | Otter Tail Corp | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Period Focus | Q2 | |
Document Fiscal Year Focus | 2019 | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Document Quarterly Report | true | |
Document Transition Report | false | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2019 | |
Entity File Number | 0-53713 | |
Entity Tax Identification Number | 27-0383995 | |
Entity Incorporation, State or Country Code | MN | |
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 | |
Trading Symbol | OTTR | |
Security Exchange Name | NASDAQ | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 39,755,277 |
Consolidated Balance Sheets (Cu
Consolidated Balance Sheets (Current Period Unaudited) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and Cash Equivalents | $ 982 | $ 861 |
Accounts Receivable: | ||
Trade—Net | 105,407 | 75,144 |
Other | 9,956 | 9,741 |
Inventories | 105,860 | 106,270 |
Unbilled Receivables | 18,349 | 23,626 |
Income Taxes Receivable | 0 | 2,439 |
Regulatory Assets | 14,501 | 17,225 |
Other | 8,511 | 6,114 |
Total Current Assets | 263,566 | 241,420 |
Investments | 9,683 | 8,961 |
Other Assets | 39,002 | 35,759 |
Goodwill | 37,572 | 37,572 |
Other Intangibles—Net | 11,858 | 12,450 |
Regulatory Assets | 131,692 | 135,257 |
Right of Use Assets - Operating Leases | 19,473 | 0 |
Plant | ||
Electric Plant in Service | 2,170,259 | 2,019,721 |
Nonelectric Operations | 234,245 | 228,120 |
Construction Work in Progress | 73,069 | 181,626 |
Total Gross Plant | 2,477,573 | 2,429,467 |
Less Accumulated Depreciation and Amortization | 875,475 | 848,369 |
Net Plant | 1,602,098 | 1,581,098 |
Total Assets | 2,114,944 | 2,052,517 |
Current Liabilities | ||
Short-Term Debt | 36,602 | 18,599 |
Current Maturities of Long-Term Debt | 177 | 172 |
Accounts Payable | 111,848 | 96,291 |
Accrued Salaries and Wages | 18,034 | 24,857 |
Accrued Federal and State Income Taxes | 3,732 | 0 |
Other Accrued Taxes | 11,753 | 17,287 |
Regulatory Liabilities | 8,959 | 738 |
Current Operating Lease Liabilities | 3,784 | 0 |
Other Accrued Liabilities | 11,260 | 12,149 |
Total Current Liabilities | 206,149 | 170,093 |
Pensions Benefit Liability | 88,030 | 98,358 |
Other Postretirement Benefits Liability | 73,080 | 71,561 |
Long-Term Operating Lease Liabilities | 16,084 | 0 |
Other Noncurrent Liabilities | 28,859 | 24,326 |
Commitments and Contingencies (note 9) | ||
Deferred Credits | ||
Deferred Income Taxes | 122,035 | 120,976 |
Deferred Tax Credits | 19,300 | 19,974 |
Regulatory Liabilities | 224,655 | 226,469 |
Other | 2,384 | 1,895 |
Total Deferred Credits | 368,374 | 369,314 |
Capitalization | ||
Long-Term Debt—Net | 590,063 | 590,002 |
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2019—39,754,902 Shares; 2018—39,664,884 Shares | 198,775 | 198,324 |
Premium on Common Shares | 345,030 | 344,250 |
Retained Earnings | 205,115 | 190,433 |
Accumulated Other Comprehensive Loss | (4,615) | (4,144) |
Total Common Equity | 744,305 | 728,863 |
Total Capitalization | 1,334,368 | 1,318,865 |
Total Liabilities and Equity | 2,114,944 | 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 | Jun. 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) | 39,754,902 | 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 | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Operating Revenues: | ||||
Total Operating Revenues | $ 229,203 | $ 226,348 | $ 475,175 | $ 467,614 |
Operating Expenses | ||||
Production Fuel – Electric | 8,296 | 15,888 | 27,216 | 34,594 |
Electric Operation and Maintenance Expenses | 39,856 | 37,741 | 78,238 | 77,216 |
Cost of Products Sold (depreciation included below) | 97,996 | 93,545 | 188,578 | 182,330 |
Other Nonelectric Expenses | 13,262 | 12,649 | 26,739 | 25,143 |
Depreciation and Amortization | 19,441 | 18,745 | 38,572 | 37,508 |
Property Taxes – Electric | 3,900 | 3,273 | 7,859 | 7,108 |
Total Operating Expenses | 202,384 | 196,243 | 408,787 | 399,894 |
Operating Income | 26,819 | 30,105 | 66,388 | 67,720 |
Interest Charges | 7,825 | 7,676 | 15,651 | 15,048 |
Nonservice Cost Components of Postretirement Benefits | 1,075 | 1,386 | 2,110 | 2,803 |
Other Income | 850 | 707 | 2,094 | 1,890 |
Income Before Income Taxes | 18,769 | 21,750 | 50,721 | 51,759 |
Income Tax Expense | 3,343 | 3,054 | 8,971 | 6,848 |
Net Income | $ 15,426 | $ 18,696 | $ 41,750 | $ 44,911 |
Average Number of Common Shares Outstanding – Basic (in shares) | 39,712,036 | 39,605,717 | 39,684,679 | 39,578,296 |
Average Number of Common Shares Outstanding – Diluted (in shares) | 39,917,831 | 39,879,069 | 39,910,499 | 39,871,376 |
Basic Earnings Per Common Share (in dollars per share) | $ 0.39 | $ 0.47 | $ 1.05 | $ 1.13 |
Diluted Earnings Per Common Share (in dollars per share) | $ 0.39 | $ 0.47 | $ 1.05 | $ 1.13 |
Electricity [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | $ 101,861 | $ 105,284 | $ 231,006 | $ 229,109 |
Changes in Accrued Revenues under Alternative Revenue Programs | 369 | (1,565) | (680) | (2,440) |
Total Electric Revenues | 102,230 | 103,719 | 230,326 | 226,669 |
Product [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | 126,973 | 122,629 | 244,849 | 240,945 |
Electricity, Purchased [Member] | ||||
Operating Expenses | ||||
Purchased Power – Electric System Use | $ 19,633 | $ 14,402 | $ 41,585 | $ 35,995 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Net Income | $ 15,426 | $ 18,696 | $ 41,750 | $ 44,911 |
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 | (4) | 0 | (4) | (110) |
Unrealized Gains (Losses) Arising During Period | 66 | (13) | 157 | (79) |
Income Tax (Expense) Benefit | (13) | 3 | (32) | 40 |
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | 49 | (10) | 121 | (149) |
Pension and Postretirement Benefit Plans: | ||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 129 | 233 | 259 | 460 |
Income Tax Expense | (33) | (61) | (67) | (120) |
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 | 192 | (191) |
Total Other Comprehensive Income (Loss) | 145 | 162 | 313 | (340) |
Total Comprehensive Income | $ 15,571 | $ 18,858 | $ 42,063 | $ 44,571 |
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) | 153,376 | ||||
Common Stock Issuances, Net of Expenses | $ 767 | (93) | |||
Common Stock Issuances, Net of Expenses | (860) | ||||
Net Income | 44,911 | 44,911 | |||
Other Comprehensive Income (Loss) | (340) | (340) | |||
Employee Stock Incentive Plan Expense | 2,253 | 2,253 | |||
Common Dividends | (26,592) | (26,592) | |||
Common Stock Retirements (in shares) | (59,431) | ||||
Common Stock Retirements | $ (297) | (2,153) | (2,450) | ||
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 |
Balance (in shares) at Mar. 31, 2018 | 39,626,594 | ||||
Balance at Mar. 31, 2018 | $ 198,133 | 341,841 | 174,209 | (6,133) | 708,050 |
Common Stock Issuances, Net of Expenses (in shares) | 25,778 | ||||
Common Stock Issuances, Net of Expenses | $ 129 | (93) | |||
Common Stock Issuances, Net of Expenses | (222) | ||||
Net Income | 18,696 | 18,696 | |||
Other Comprehensive Income (Loss) | 162 | 162 | |||
Employee Stock Incentive Plan Expense | 1,107 | 1,107 | |||
Common Dividends | (13,300) | (13,300) | |||
Common Stock Retirements (in shares) | (936) | ||||
Common Stock Retirements | $ (5) | (36) | (41) | ||
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 |
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) | 145,242 | ||||
Common Stock Issuances, Net of Expenses | $ 727 | 17 | |||
Common Stock Issuances, Net of Expenses | (710) | ||||
Net Income | 41,750 | 41,750 | |||
Other Comprehensive Income (Loss) | 313 | 313 | |||
Employee Stock Incentive Plan Expense | 3,944 | 3,944 | |||
Common Dividends | (27,852) | (27,852) | |||
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 Jun. 30, 2019 | 39,754,902 | ||||
Balance at Jun. 30, 2019 | $ 198,775 | 345,030 | 205,115 | (4,615) | 744,305 |
Balance (in shares) at Mar. 31, 2019 | 39,729,708 | ||||
Balance at Mar. 31, 2019 | $ 198,649 | 342,991 | 203,619 | (4,760) | 740,499 |
Common Stock Issuances, Net of Expenses (in shares) | 25,194 | ||||
Common Stock Issuances, Net of Expenses | $ 126 | 17 | |||
Common Stock Issuances, Net of Expenses | (109) | ||||
Net Income | 15,426 | 15,426 | |||
Other Comprehensive Income (Loss) | 145 | 145 | |||
Employee Stock Incentive Plan Expense | 2,148 | 2,148 | |||
Common Dividends | (13,930) | (13,930) | |||
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 |
Consolidated Statements of Co_2
Consolidated Statements of Common Shareholders' Equity (Unaudited) (Parentheticals) - $ / shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Retained Earnings [Member] | ||||
Dividends Declared Per Common Share (in dollars per share) | $ 0.35 | $ 0.335 | $ 0.70 | $ 0.67 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Cash Flows from Operating Activities | ||
Net Income | $ 41,750 | $ 44,911 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Depreciation and Amortization | 38,572 | 37,508 |
Deferred Tax Credits | (674) | (703) |
Deferred Income Taxes | 960 | 2,076 |
Change in Deferred Debits and Other Assets | 3,884 | 10,309 |
Discretionary Contribution to Pension Plan | (10,000) | (20,000) |
Change in Noncurrent Liabilities and Deferred Credits | 11,942 | (759) |
Allowance for Equity/Other Funds Used During Construction | (688) | (1,060) |
Stock Compensation Expense—Equity Awards | 3,944 | 2,253 |
Other—Net | 276 | (193) |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (30,478) | (25,677) |
Change in Inventories | 410 | (2,401) |
Change in Other Current Assets | 2,870 | 2,428 |
Change in Payables and Other Current Liabilities | 222 | 1,233 |
Change in Interest and Income Taxes Receivable/Payable | 6,297 | 3,470 |
Net Cash Provided by Operating Activities | 69,287 | 53,395 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (54,012) | (49,094) |
Net Proceeds from Disposal of Noncurrent Assets | 3,405 | 1,477 |
Cash Used for Investments and Other Assets | (4,776) | (2,102) |
Net Cash Used in Investing Activities | (55,383) | (49,719) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | (1,120) | 2,236 |
Net Short-Term Borrowings (Repayments) | 18,003 | (91,394) |
Common Stock Issuance Expenses | 0 | (108) |
Payments for Retirement of Capital Stock | (2,730) | (2,450) |
Proceeds from Issuance of Long-Term Debt | 0 | 100,000 |
Short-Term and Long-Term Debt Issuance Expenses | 0 | (441) |
Payments for Retirement of Long-Term Debt | (84) | (107) |
Dividends Paid | (27,852) | (26,592) |
Net Cash Used in Financing Activities | (13,783) | (18,856) |
Net Change in Cash and Cash Equivalents | 121 | (15,180) |
Cash and Cash Equivalents at Beginning of Period | 861 | 16,216 |
Cash and Cash Equivalents at End of Period | $ 982 | $ 1,036 |
Note 1 - Summary of Significant
Note 1 - Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 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 ) (ASC 606 ), the Company also records adjustments to Electric segment revenues for amounts subject to future collection under alternative revenue programs (ARPs) as defined in ASC Topic 980, Reg ul ated Operations (ASC 980 ). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers. Electric Segment Revenues —In the Electric segment, the Company recognizes revenue in two categories: ( 1 ) revenues from contracts with customers and ( 2 ) adjustments to revenues for amounts collectible under ARPs. 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 source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer. 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) and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 for total revenues billed and accrued under ARP riders for the three - and six -month periods ended June 30, 2019 and 2018. Manufacturing Segment Revenues —Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point. Plastics Segment Revenues —Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is also recognized over time as the pipe is stored. See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three - and six -month periods ended June 30, 2019 and 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 offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820 ), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange. Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018: June 30, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,483 Corporate Debt Securities – Held by Captive Insurance Company $ 3,368 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,701 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,311 Total Assets $ 2,794 $ 8,069 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 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company are determined on the basis of valuations provided by a third -party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes. Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements. If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2019 could be as high as million, OTP’s share of unrecovered costs. Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: June 30, December 31, (in thousands) 2019 2018 Finished Goods $ 32,699 $ 37,130 Work in Process 19,414 20,393 Raw Material, Fuel and Supplies 53,747 48,747 Total Inventories $ 105,860 $ 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 indicated the fair values are substantially in excess of their respective book values and no impaired. The following table indicates there were changes to goodwill by business segment during the first six months of 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) June 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 June 30, 2019 and December 31, 2018: June 30, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,693 $ 11,798 6 - 194 Other 154 94 60 14 Total $ 22,645 $ 10,787 $ 11,858 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 Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345 $ 592 $ 690 The estimated annual amortization expense for these intangible assets for the next five years is: (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 June 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,841 $ 11,564 New Accounting Standards Adopted ASU 2016 - 02 —In February 2016 the FASB issued ASU No. 2016 - 02, Leases (Topic 842 ) (ASU 2016 - 02 ). ASU 2016 - 02 is a comprehensive amendment of the ASC, creating Topic 842, which supersedes the requirements under ASC Topic 840 on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU 2016 - 02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The Company adopted the amendments in ASU 2016 - 02 to its consolidated financial statements effective January 1, 2019. See note 8 for further information on leases and the Company’s elections for applying the new standard. ASU 2018 - 02 —In February 2018 the FASB issued ASU No. 2018 - 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018 - 02 ). The amendments in ASU 2018 - 02, which are narrow in scope, allow a reclassification from accumulated other comprehensive income/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. The amendments in ASU 2018 - 02 also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The amendments in ASU 2018 - 02 can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company adopted the updates in ASU 2018 - 02 effective January 1, 2019, applying them in the period of adoption and not retrospectively. On adoption, the Company reclassified of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates. 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 —In January 2017 the FASB issued ASU No. 2017 - 04, Intangibles—Goodwill and Other (Topic 350 ): Simplifying the Test for Goodwill Impairment (ASU 2017 - 04 ), which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step 2, an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU 2017 - 04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. The amendments in ASU 2017 - 04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017 - 04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company early adopted the amendments in ASU 2017 - 04 in the first quarter of 2019. The Company had no indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had no impact on the Company’s consolidated financial statements. New Accounting Standards Pending Adoption ASU 2016 - 13 —In June 2016 the FASB issued ASU No. 2016 - 13, Financial Instruments—Credit Losses (Topic 326 ) (ASC Topic 326 ) , which changes how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after December 15, 2019. The Company is currently evaluating what impact adoption of the new standard may have on its consolidated financial statements. |
Note 2 - Segment Information
Note 2 - Segment Information | 6 Months Ended |
Jun. 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 provided 11.2% of 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 98.2% of operating revenues for the respective three June 30, 2019 2018, six June 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 six June 30, 2019 2018 June 30, 2019 December 31, 2018 Operating Revenue Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 87,976 $ 89,400 $ 202,931 $ 198,580 Changes in Accrued ARP Revenues 369 (1,565 ) (680 ) (2,440 ) Total Retail Sales Revenue 88,345 87,835 202,251 196,140 Transmission Services Revenue 11,469 11,313 22,331 23,216 Wholesale Revenues – Company Generation 941 2,539 2,468 3,554 Other Revenues 1,489 2,038 3,303 3,780 Total Electric Segment Revenues 102,244 103,725 230,353 226,690 Manufacturing Segment: Metal Parts and Tooling 62,541 57,388 129,265 114,315 Plastic Products and Tooling 9,353 7,961 18,398 18,196 Other 1,602 2,805 3,655 4,305 Total Manufacturing Segment Revenues 73,496 68,154 151,318 136,816 Plastics Segment – Sale of PVC Pipe Products 53,476 54,476 93,534 104,129 Intersegment Eliminations (13 ) (7 ) (30 ) (21 ) Total $ 229,203 $ 226,348 $ 475,175 $ 467,614 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,625 $ 6,687 $ 13,266 $ 13,077 Manufacturing 646 555 1,230 1,109 Plastics 215 160 364 310 Corporate and Intersegment Eliminations 339 274 791 552 Total $ 7,825 $ 7,676 $ 15,651 $ 15,048 Income Taxes Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 1,037 $ 611 $ 5,808 $ 2,709 Manufacturing 1,149 1,018 2,603 2,241 Plastics 2,044 2,207 3,373 4,621 Corporate (887 ) (782 ) (2,813 ) (2,723 ) Total $ 3,343 $ 3,054 $ 8,971 $ 6,848 Net Income (Loss) Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 7,502 $ 10,600 $ 26,202 $ 27,268 Manufacturing 3,990 3,583 8,832 7,747 Plastics 5,792 6,229 9,521 13,073 Corporate (1,858 ) (1,716 ) (2,805 ) (3,177 ) Total $ 15,426 $ 18,696 $ 41,750 $ 44,911 Identifiable Assets June 30, December 31, (in thousands) 2019 2018 Electric $ 1,752,432 $ 1,728,534 Manufacturing 211,374 187,556 Plastics 104,762 91,630 Corporate 46,376 44,797 Total $ 2,114,944 $ 2,052,517 |
Note 3 - Rate and Regulatory Ma
Note 3 - Rate and Regulatory Matters | 6 Months Ended |
Jun. 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 September 26, 2018 March 6, 2019 December 2018 January 2019. May 2019. June 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, $37.7 August 2019. June 30, 2019, Big Stone South–Ellendale Multi-Value Transmission Project (MVP) February 6, 2019, December 2011. June 30, 2019 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 Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision would vary over time and be dependent on the differences between the revenue requirements and returns in the 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 June 30, 2019 Environmental Cost Recovery Rider 2010 2016 November 2017. 2018 December 1, 2018. March April 2019. Renewable Resource Adjustment November 1, 2017, 2017 2018. June 21, 2019 North Dakota General Rates November 2, 2017 $13.1 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 Environmental Cost Recovery Rider 2017 February 1, 2019, February 1, 2019 Generation Cost Recovery Rider March 1, 2019 May 15, 2019. 2.547% July 1, 2019. South Dakota General Rate s 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 June 28, 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 9.50% 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. Environmental Cost Recovery Rider October 18, 2018 Phase-In Rider On May 31, 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 June 30, Six Months Ended June 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,618 $ 2,368 $ 4,770 $ 4,884 Renewable Resource Recovery 1,317 659 2,633 1,184 Transmission Cost Recovery (56 ) (458 ) 585 (487 ) Environmental Cost Recovery - (18 ) (1 ) (49 ) North Dakota Transmission Cost Recovery 874 1,165 2,646 3,227 Renewable Resource Adjustment (93 ) 2,079 636 4,046 Environmental Cost Recovery (12 ) 1,830 563 3,651 Generation Cost Recovery 222 - 470 - South Dakota Transmission Cost Recovery 371 250 844 786 Conservation Improvement Program Costs and Incentives 96 122 340 351 Environmental Cost Recovery (23 ) 515 (27 ) 1,035 Total $ 5,314 $ 8,512 $ 13,459 $ 18,628 1 Includes MNCIP costs recovered in base rates. Rate Rider Updates The following table provides summary information on the status of updates since January 1, 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 R – April 1, 2019 October 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 R – June 21, 2019 November 1, 2019 $ 12,571 $0.00469 /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 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 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 R – July 31, 2019 October 1, 2019 $ 2,050 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 2019 Initial Request R – May 31, 2019 September 1, 2019 $ 1,027 3.942% of base TCJA The TCJA, passed in December 2017, January 1, 2018. 35% 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. June 30, 2019, one $11.5 January 2018 May 2019 August 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 June 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 On 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 12.38% 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 June 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 third fourth 2019. OTP believes its estimated accrued MISO Tariff ROE refund liability of $1.6 million as of June 30, 2019 second |
Note 4 - Regulatory Assets and
Note 4 - Regulatory Assets and Liabilities | 6 Months Ended |
Jun. 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 June 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 $ 115,246 $ 121,601 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,436 7,436 asset lives Conservation Improvement Program Costs and Incentives 2 1,861 4,659 6,520 27 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,637 - 2,637 12 Deferred Marked-to-Market Losses 1 1,202 372 1,574 18 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,359 1,359 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 698 590 1,288 22 Debt Reacquisition Premiums 1 203 649 852 159 Deferred Income Taxes 1 - 701 701 asset lives North Dakota Generation Cost Recovery Rider Accrued Revenues 2 470 - 470 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 263 379 39 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 377 - 377 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 120 222 342 30 Minnesota SPP Transmission Cost Recovery Tracker 1 - 148 148 see below Deferred Lease Expenses 1 - 47 47 45 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 3 - 3 12 Total Regulatory Assets $ 14,501 $ 131,692 $ 146,193 Regulatory Liabilities: Deferred Income Taxes $ - $ 140,226 $ 140,226 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,977 83,977 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 5,087 - 5,087 12 Refundable Fuel Clause Adjustment Revenues – North Dakota 1,676 - 1,676 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 725 - 725 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 614 - 614 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 391 - 391 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 284 284 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 94 93 187 18 South Dakota Transmission Cost Recovery Rider Accrued Refund 146 - 146 12 Refundable Fuel Clause Adjustment Revenues – South Dakota 130 - 130 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 45 - 45 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 45 - 45 4 Other 6 75 81 174 Total Regulatory Liabilities $ 8,959 $ 224,655 $ 233,614 Net Regulatory Asset/(Liability) Position $ 5,542 $ (92,963 ) $ (87,421 ) 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 Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 Deferred Income Taxes 1 - 2,423 2,423 asset lives 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 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 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 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 Refundable Fuel Clause Adjustment Revenues 121 - 121 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 are recoverable from Minnesota customers as of June 30, 2019. All Deferred Marked-to-Market Losses recorded as of June 30, 2019 December 2020. 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. 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 159 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 North Dakota Generation Cost Recovery (NDGCR) 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 June 30, 2019 not South Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current 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 current rate case in North Dakota currently being recovered beginning with the establishment of interim rates in January 2018. MISO Schedule 26/26A 26/26A The Minnesota SPP Transmission Cost Recovery Tracker regulatory asset relates to costs incurred to serve Minnesota customers that are subject to recovery but that have not June 30, 2019. Deferred Lease Expenses: Under ASC 842 June 30, 2019 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 are recoverable from Minnesota customers as of June 30, 2019. The Minnesota Renewable Resource Recovery Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that are recoverable from Minnesota customers as of June 30, 2019. Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues relate to revenues recorded for fuel and purchased power costs reductions provided to customers in energy intensive trade exposed industries that are subject to recovery from other Minnesota customers. 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 December 31, 2018. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. North Dakota Renewable Resource Recovery Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of June 30, 2019. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of June 30, 2019. February 1, 2019 The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of June 30, 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 South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of June 30, 2019. The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of June 30, 2019. 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 are subject to refund to Minnesota customers. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980 |
Note 5 - Common Shares and Earn
Note 5 - Common Shares and Earnings Per Share | 6 Months Ended |
Jun. 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 June 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 26,750 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, June 30, 2019 39,754,902 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three six June 30, 2019 2018. not Three Months ended June 30 Six Months ended June 30 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,712,036 39,605,717 39,684,679 39,578,296 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 134,137 202,643 146,148 212,902 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 60,168 57,616 61,783 58,373 Nonvested Restricted Shares 9,657 10,733 15,790 19,188 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,833 2,360 2,099 2,617 Total Dilutive Shares 205,795 273,352 225,820 293,080 Weighted Average Common Shares Outstanding – Diluted 39,917,831 39,879,069 39,910,499 39,871,376 The effect of dilutive shares on earnings per share for the three six June 30, 2019 2018, no $0.01 |
Note 6 - Share-based Payments
Note 6 - Share-based Payments | 6 Months Ended |
Jun. 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 six June 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 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. As of June 30, 2019, Amounts of compensation expense recognized under the Company’s stock-based payment programs for the three six June 30, 2019 2018 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 1,418 $ 668 $ 2,531 $ 1,319 Restricted Stock Units Granted to Executive Officers 383 173 810 422 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 204 165 369 331 Restricted Stock Units Granted to Key Employees 143 101 234 165 Totals $ 2,148 $ 1,107 $ 3,944 $ 2,253 In July 2019 not |
Note 7 - Retained Earnings and
Note 7 - Retained Earnings and Dividend Restriction | 6 Months Ended |
Jun. 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 June 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 47.9% and 58.5% based on OTP’s 2018 October 18, 2018. June 30, 2019, On May 1, 2019 not 2019 2019 July 19, 2019. |
Note 8 - Leases
Note 8 - Leases | 6 Months Ended |
Jun. 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 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 1 year to approximately 10 years. If a lease contains an option to extend and there is reasonable certainty the option will be exercised, the option is considered in the lease term at inception. 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 June 30, 2019 (in thousands) Electric Manufacturing Plastics Corporate Total Right of Use Assets – Operating Leases: Gross $ 3,586 $ 16,630 $ 666 $ 769 $ 21,651 Accumulated Amortization (526 ) (1,393 ) (195 ) (64 ) (2,178 ) Net of Accumulated Amortization $ 3,060 $ 15,237 $ 471 $ 705 $ 19,473 Obligations: Current Operating Lease Liabilities $ 975 $ 2,303 $ 353 $ 153 $ 3,784 Long-Term Operating Lease Liabilities 2,336 13,019 118 611 16,084 Total Lease Liabilities $ 3,311 $ 15,322 $ 471 $ 764 $ 19,868 The amounts of the Company’s right-of-use operating lease obligations for each of the five 2019 2023 2023 not June 30, 2019. Right-of-Use Operating Leases (in thousands) OTP Nonelectric Total 2019 $ 570 $ 2,055 $ 2,625 2020 1,115 3,872 4,987 2021 1,100 3,600 4,700 2022 207 3,465 3,672 2023 196 3,174 3,370 Beyond 2023 447 8,022 8,469 Total Minimum Obligations $ 3,635 $ 24,188 $ 27,823 Interest Component of Obligations (314 ) (4,115 ) (4,429 ) Present Value of Leases Commencing after June 30, 2019 (10 ) (3,516 ) (3,526 ) Present Value of Minimum Obligations, June 30, 2019 $ 3,311 $ 16,557 $ 19,868 The Company’s total minimum lease obligations reported in the table above includes obligations for a 10-year lease of a warehouse by T.O. Plastics entered into in 2018 July 2019 one July 2019. The weighted-average remaining lease term for the Company’s outstanding lease liabilities is 5.8 years and the weighted-average discount rate is 5.0%. A reconciliation of the Company’s operating lease obligations on adoption of ASC Topic 842 January 1, 2019 June 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 167 1,725 1,892 Lease Modifications - (1,366 ) (1,366 ) Lease Obligation Payments (551 ) (992 ) (1,543 ) Interest Component of Lease Obligation Payment 86 430 516 Operating Lease Obligations, June 30, 2019 $ 3,311 $ 16,557 $ 19,868 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 six June 30, 2019 Three Months Ended June 30, 2019 Six Months Ended June 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 $ 11 $ - $ 11 $ 20 $ - $ 20 Inventory 238 - 238 463 - 463 Cost of Products Sold 943 45 988 1,979 72 2,051 Electric Operation and Maintenance Expenses 64 - 64 130 - 130 Other Nonelectric Expenses 51 1 52 105 1 106 Total 1,307 $ 46 $ 1,353 $ 2,697 $ 73 $ 2,770 |
Note 9 - Commitments and Contin
Note 9 - Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2019 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | 9. Construction and Other Purchase Commitments At June 30, 2019 2021 December 31, 2018 June 30, 2019 December 31, 2021 December 31, 2018 December 31, 2021 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 2019 December 31, 2023. no 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 June 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. The Company currently is not In 2015 111 not 2016. 2017, April 2018. On August 21, 2018 not June 19, 2019 September 6, 2019. two not 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 June 30, 2019 not |
Note 10 - Short-term and Long-t
Note 10 - Short-term and Long-term Borrowings | 6 Months Ended |
Jun. 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 June 30, 2019 December 31, 2018: (in thousands) Line Limit In Use on June 30, 2019 Restricted due to Outstanding Letters of Credit Available on June 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 13,801 $ - $ 116,199 $ 120,785 OTP Credit Agreement 170,000 22,801 8,766 138,433 160,316 Total $ 300,000 $ 36,602 $ 8,766 $ 254,632 $ 281,101 The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2019 December 31, 2018: June 30 , 201 9 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 22,801 $ 13,801 $ 36,602 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 438 438 Total $ 512,000 $ 80,438 $ 592,438 Less: Current Maturities net of Unamortized Debt Issuance Costs - 177 177 Unamortized Long-Term Debt Issuance Costs 1,816 382 2,198 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,184 $ 79,879 $ 590,063 Total Short-Term and Long-Term Debt (with current maturities) $ 532,985 $ 93,857 $ 626,842 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 Othe
Note 11 - Pension Plan and Other Postretirement Benefits | 6 Months Ended |
Jun. 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 June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 2,746 $ 3,230 Interest Cost on Projected Benefit Obligation 3,603 3,363 7,206 6,726 Expected Return on Assets (5,324 ) (5,299 ) (10,649 ) (10,599 ) Amortization of Prior-Service Cost: From Regulatory Asset 2 4 3 8 From Other Comprehensive Income 1 2 - 4 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,162 1,783 2,325 3,567 From Other Comprehensive Income 1 26 47 53 91 Net Periodic Pension Cost 2 $ 844 $ 1,513 $ 1,688 $ 3,023 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 336 $ 379 $ 726 $ 707 Service costs included in electric operation and maintenance expenses 1,004 1,195 1,954 2,442 Service costs included in other nonelectric expenses 33 40 66 80 Nonservice costs capitalized as regulatory assets (130 ) (24 ) (280 ) (45 ) Nonservice costs included in n onservice cost components of postretirement benefits (399 ) (77 ) (778 ) (161 ) Cash flows no December 31, 2018 January 2019. Executive Survivor and Supplemental Retirement Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 209 $ 200 Interest Cost on Projected Benefit Obligation 434 399 868 798 Amortization of Prior-Service Cost: From Regulatory Asset 1 4 2 8 From Other Comprehensive Income 1 4 9 8 19 Amortization of Net Actuarial Loss: From Regulatory Asset 31 67 62 134 From Other Comprehensive Income 1 88 165 175 330 Net Periodic Pension Cost 2 $ 662 $ 744 $ 1,324 $ 1,489 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 $ 25 $ 52 $ 50 Service costs included in other nonelectric expenses 78 75 157 150 Nonservice costs included in n onservice cost components of postretirement benefits 558 644 1,115 1,289 Other Postretirement Benefits Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 322 $ 381 $ 643 $ 763 Interest Cost on Projected Benefit Obligation 772 646 1,542 1,291 Amortization of Net Actuarial Loss: From Regulatory Asset 392 412 785 824 From Other Comprehensive Income 1 9 11 19 21 Net Periodic Postretirement Benefit Cost 2 $ 1,495 $ 1,450 $ 2,989 $ 2,899 Effect of Medicare Part D Subsidy $ (44 ) $ (36 ) $ (89 ) $ (73 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 79 $ 89 $ 170 $ 167 Service costs included in electric operation and maintenance expenses 235 283 458 577 Service costs included in other nonelectric expenses 8 9 15 19 Nonservice costs capitalized as regulatory assets 288 251 621 468 Nonservice costs included in n onservice cost components of postretirement benefits 885 818 1,725 1,668 |
Note 12 - Fair Value of Financi
Note 12 - Fair Value of Financial Instruments | 6 Months Ended |
Jun. 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 June 30, 2019 December 31, 2018 1.50% Long-Term Debt including Current Maturities 2 820. June 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 982 $ 982 $ 861 $ 861 Short-Term Debt (36,602 ) (36,602 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,240 ) (631,747 ) (590,174 ) (601,513 ) |
Note 13 - Property, Plant and E
Note 13 - Property, Plant and Equipment | 6 Months Ended |
Jun. 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 | 6 Months Ended |
Jun. 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 six June 30, 2019 2018: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 18,769 $ 21,750 $ 50,721 $ 51,759 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 4,879 $ 5,655 $ 13,187 $ 13,457 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (774 ) (1,025 ) (1,757 ) (2,098 ) Excess Tax Deduction – Equity Method Stock Awards - - (827 ) (624 ) Corporate Owned Life Insurance (150 ) (17 ) (559 ) (25 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (516 ) (516 ) Research and Development and Other Tax Credits (187 ) (180 ) (375 ) (360 ) Allowance for Funds Used During Construction – Equity (94 ) (111 ) (180 ) (278 ) Federal Production Tax Credits - (930 ) - (2,050 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (73 ) (80 ) (2 ) (127 ) Income Tax Expense $ 3,343 $ 3,054 $ 8,971 $ 6,848 Effective Income Tax Rate 17.8 % 14.0 % 17.7 % 13.2 % 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 Decreases Related to Tax Positions for Prior Years - - Increases Related to Tax Positions for Current Year 75 72 Uncertain Positions Resolved During Year (42 ) (44 ) Balance on June 30 $ 1,315 $ 712 The balance of unrecognized tax benefits as of June 30, 2019 June 30, 2019 not June 30, 2019. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of August 1, 2019, no 2015 |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 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 ) (ASC 606 ), the Company also records adjustments to Electric segment revenues for amounts subject to future collection under alternative revenue programs (ARPs) as defined in ASC Topic 980, Reg ul ated Operations (ASC 980 ). The ARP revenue adjustments are recorded on the basis of recoverable costs incurred and returns earned under rate riders on a separate line on the face of the Company’s consolidated statements of income as they do not meet the criteria to be classified as revenue from contracts with customers. Electric Segment Revenues —In the Electric segment, the Company recognizes revenue in two categories: ( 1 ) revenues from contracts with customers and ( 2 ) adjustments to revenues for amounts collectible under ARPs. 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 source of revenue for OTP comes from the generation and sale of electricity to wholesale customers at contract or market rates. Revenues from all these sources meet the criteria to be classified as revenue from contracts with customers and are recognized over time as energy is delivered or transmitted. Revenue is recognized based on the metered quantity of electricity delivered or transmitted at the applicable rates. For electricity delivered and consumed after a meter is read but prior to the end of the reporting period, OTP records revenue and an unbilled receivable based on estimates of the kilowatt-hours (kwh) of energy delivered to the customer. 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) and Conservation Improvement Program riders. ● In North Dakota: TCR, ECR, RRA and Generation Cost Recovery (GCR) riders. ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 for total revenues billed and accrued under ARP riders for the three - and six -month periods ended June 30, 2019 and 2018. Manufacturing Segment Revenues —Companies in the Manufacturing segment, BTD Manufacturing, Inc. (BTD) and T.O. Plastics, Inc. (T.O. Plastics), earn revenue predominantly from the production and delivery of custom-made or standardized parts to customers across several industries. BTD also earns revenue from the production and sale of tools and dies to other manufacturers. For the production and delivery of standardized products and other products made to customer specifications where the terms of the contract require transfer of the completed product, the operating company has met its performance obligation and recognizes revenue at the point in time when the product is shipped. For revenue recognized on products when shipped, the operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point. Plastics Segment Revenues —Companies in our Plastics segment earn revenue predominantly from the sale and delivery of standardized polyvinyl chloride (PVC) pipe products produced at their manufacturing facilities. Revenue from the sale of these products is recognized at the point in time when the product is shipped based on prices agreed to in a purchase order. For revenue recognized on shipped products, there is no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. The Plastics segment has one customer for which it produces and stores a product made to the customer’s specifications and design under a build and hold agreement. For sales to this customer, the operating company recognizes revenue as the custom-made product is produced, adjusting the amount of revenue for volume rebate variable pricing considerations the operating company expects the customer will earn and applicable early payment discounts the company expects the customer will take. Ownership of the pipe transfers to the customer prior to delivery and the operating company is paid a negotiated fee for storage of the pipe. Revenue for storage of the pipe is also recognized over time as the pipe is stored. See operating revenue table in note 2 for a disaggregation of the Company’s revenues by business segment for the three - and six -month periods ended June 30, 2019 and 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 offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820 ), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange. Level 2 – Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2019 and December 31, 2018: June 30, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,483 Corporate Debt Securities – Held by Captive Insurance Company $ 3,368 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,701 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,311 Total Assets $ 2,794 $ 8,069 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 fair values for Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company are determined on the basis of valuations provided by a third -party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes. |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements. If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of June 30, 2019 could be as high as million, OTP’s share of unrecovered costs. |
Inventory, Policy [Policy Text Block] | Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: June 30, December 31, (in thousands) 2019 2018 Finished Goods $ 32,699 $ 37,130 Work in Process 19,414 20,393 Raw Material, Fuel and Supplies 53,747 48,747 Total Inventories $ 105,860 $ 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 indicated the fair values are substantially in excess of their respective book values and no impaired. The following table indicates there were changes to goodwill by business segment during the first six months of 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) June 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 June 30, 2019 and December 31, 2018: June 30, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,693 $ 11,798 6 - 194 Other 154 94 60 14 Total $ 22,645 $ 10,787 $ 11,858 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 Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345 $ 592 $ 690 The estimated annual amortization expense for these intangible assets for the next five years is: (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 June 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,841 $ 11,564 |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Standards Adopted ASU 2016 - 02 —In February 2016 the FASB issued ASU No. 2016 - 02, Leases (Topic 842 ) (ASU 2016 - 02 ). ASU 2016 - 02 is a comprehensive amendment of the ASC, creating Topic 842, which supersedes the requirements under ASC Topic 840 on leases and requires the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The amendments in ASU 2016 - 02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The Company adopted the amendments in ASU 2016 - 02 to its consolidated financial statements effective January 1, 2019. See note 8 for further information on leases and the Company’s elections for applying the new standard. ASU 2018 - 02 —In February 2018 the FASB issued ASU No. 2018 - 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018 - 02 ). The amendments in ASU 2018 - 02, which are narrow in scope, allow a reclassification from accumulated other comprehensive income/(loss) (AOCI/(L)) to retained earnings for the stranded tax effects resulting from the Tax Cuts and Jobs Act (TCJA). Consequently, the amendments eliminate the stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. The amendments in ASU 2018 - 02 also require certain disclosures about stranded tax effects and are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The amendments in ASU 2018 - 02 can be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. The Company adopted the updates in ASU 2018 - 02 effective January 1, 2019, applying them in the period of adoption and not retrospectively. On adoption, the Company reclassified of income tax effects of the TCJA on the gross deferred tax amounts reflected in AOCI/(L) at the date of enactment of the TCJA from AOCI/(L) to retained earnings so the remaining gross deferred tax amounts related to items in AOCI/(L) will reflect current effective tax rates. 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 —In January 2017 the FASB issued ASU No. 2017 - 04, Intangibles—Goodwill and Other (Topic 350 ): Simplifying the Test for Goodwill Impairment (ASU 2017 - 04 ), which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. In computing the implied fair value of goodwill under Step 2, an entity must perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination. Under the amendments in ASU 2017 - 04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. The amendments in ASU 2017 - 04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017 - 04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company early adopted the amendments in ASU 2017 - 04 in the first quarter of 2019. The Company had no indication that any of its goodwill was impaired, therefore, the adoption of the updated standard had no impact on the Company’s consolidated financial statements. New Accounting Standards Pending Adoption ASU 2016 - 13 —In June 2016 the FASB issued ASU No. 2016 - 13, Financial Instruments—Credit Losses (Topic 326 ) (ASC Topic 326 ) , which changes how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after December 15, 2019. The Company is currently evaluating what impact adoption of the new standard may have on its consolidated financial statements. |
Note 1 - Summary of Significa_2
Note 1 - Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | June 30, 201 9 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,483 Corporate Debt Securities – Held by Captive Insurance Company $ 3,368 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 4,701 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 1,311 Total Assets $ 2,794 $ 8,069 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] | June 30, December 31, (in thousands) 2019 2018 Finished Goods $ 32,699 $ 37,130 Work in Process 19,414 20,393 Raw Material, Fuel and Supplies 53,747 48,747 Total Inventories $ 105,860 $ 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) June 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] | June 30, 201 9 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 10,693 $ 11,798 6 - 194 Other 154 94 60 14 Total $ 22,645 $ 10,787 $ 11,858 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 Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Amortization Expense – Intangible Assets $ 296 $ 345 $ 592 $ 690 |
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 June 30, (in thousands) 2019 2018 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 16,841 $ 11,564 |
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) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 87,976 $ 89,400 $ 202,931 $ 198,580 Changes in Accrued ARP Revenues 369 (1,565 ) (680 ) (2,440 ) Total Retail Sales Revenue 88,345 87,835 202,251 196,140 Transmission Services Revenue 11,469 11,313 22,331 23,216 Wholesale Revenues – Company Generation 941 2,539 2,468 3,554 Other Revenues 1,489 2,038 3,303 3,780 Total Electric Segment Revenues 102,244 103,725 230,353 226,690 Manufacturing Segment: Metal Parts and Tooling 62,541 57,388 129,265 114,315 Plastic Products and Tooling 9,353 7,961 18,398 18,196 Other 1,602 2,805 3,655 4,305 Total Manufacturing Segment Revenues 73,496 68,154 151,318 136,816 Plastics Segment – Sale of PVC Pipe Products 53,476 54,476 93,534 104,129 Intersegment Eliminations (13 ) (7 ) (30 ) (21 ) Total $ 229,203 $ 226,348 $ 475,175 $ 467,614 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 6,625 $ 6,687 $ 13,266 $ 13,077 Manufacturing 646 555 1,230 1,109 Plastics 215 160 364 310 Corporate and Intersegment Eliminations 339 274 791 552 Total $ 7,825 $ 7,676 $ 15,651 $ 15,048 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 1,037 $ 611 $ 5,808 $ 2,709 Manufacturing 1,149 1,018 2,603 2,241 Plastics 2,044 2,207 3,373 4,621 Corporate (887 ) (782 ) (2,813 ) (2,723 ) Total $ 3,343 $ 3,054 $ 8,971 $ 6,848 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2019 2018 2019 2018 Electric $ 7,502 $ 10,600 $ 26,202 $ 27,268 Manufacturing 3,990 3,583 8,832 7,747 Plastics 5,792 6,229 9,521 13,073 Corporate (1,858 ) (1,716 ) (2,805 ) (3,177 ) Total $ 15,426 $ 18,696 $ 41,750 $ 44,911 June 30, December 31, (in thousands) 2019 2018 Electric $ 1,752,432 $ 1,728,534 Manufacturing 211,374 187,556 Plastics 104,762 91,630 Corporate 46,376 44,797 Total $ 2,114,944 $ 2,052,517 |
Note 3 - Rate and Regulatory _2
Note 3 - Rate and Regulatory Matters (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Revenues Recorded under Rate Riders [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2019 2018 2019 2018 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,618 $ 2,368 $ 4,770 $ 4,884 Renewable Resource Recovery 1,317 659 2,633 1,184 Transmission Cost Recovery (56 ) (458 ) 585 (487 ) Environmental Cost Recovery - (18 ) (1 ) (49 ) North Dakota Transmission Cost Recovery 874 1,165 2,646 3,227 Renewable Resource Adjustment (93 ) 2,079 636 4,046 Environmental Cost Recovery (12 ) 1,830 563 3,651 Generation Cost Recovery 222 - 470 - South Dakota Transmission Cost Recovery 371 250 844 786 Conservation Improvement Program Costs and Incentives 96 122 340 351 Environmental Cost Recovery (23 ) 515 (27 ) 1,035 Total $ 5,314 $ 8,512 $ 13,459 $ 18,628 |
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 R – April 1, 2019 October 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 R – June 21, 2019 November 1, 2019 $ 12,571 $0.00469 /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 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 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 R – July 31, 2019 October 1, 2019 $ 2,050 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 2019 Initial Request R – May 31, 2019 September 1, 2019 $ 1,027 3.942% of base |
Note 4 - Regulatory Assets an_2
Note 4 - Regulatory Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | June 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 $ 115,246 $ 121,601 see below Accumulated ARO Accretion/Depreciation Adjustment 1 - 7,436 7,436 asset lives Conservation Improvement Program Costs and Incentives 2 1,861 4,659 6,520 27 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 2,637 - 2,637 12 Deferred Marked-to-Market Losses 1 1,202 372 1,574 18 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 1,359 1,359 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 698 590 1,288 22 Debt Reacquisition Premiums 1 203 649 852 159 Deferred Income Taxes 1 - 701 701 asset lives North Dakota Generation Cost Recovery Rider Accrued Revenues 2 470 - 470 12 South Dakota Deferred Rate Case Expenses Subject to Recovery 1 455 - 455 12 Big Stone II Unrecovered Project Costs – South Dakota 1 116 263 379 39 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 377 - 377 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 120 222 342 30 Minnesota SPP Transmission Cost Recovery Tracker 1 - 148 148 see below Deferred Lease Expenses 1 - 47 47 45 Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 4 - 4 12 Minnesota Renewable Resource Recovery Rider Accrued Revenues 2 3 - 3 12 Total Regulatory Assets $ 14,501 $ 131,692 $ 146,193 Regulatory Liabilities: Deferred Income Taxes $ - $ 140,226 $ 140,226 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage - 83,977 83,977 asset lives Refundable Fuel Clause Adjustment Revenues – Minnesota 5,087 - 5,087 12 Refundable Fuel Clause Adjustment Revenues – North Dakota 1,676 - 1,676 12 North Dakota Renewable Resource Recovery Rider Accrued Refund 725 - 725 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 614 - 614 12 North Dakota Transmission Cost Recovery Rider Accrued Refund 391 - 391 12 Revenue for Rate Case Expenses Subject to Refund – Minnesota - 284 284 see below MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 94 93 187 18 South Dakota Transmission Cost Recovery Rider Accrued Refund 146 - 146 12 Refundable Fuel Clause Adjustment Revenues – South Dakota 130 - 130 12 South Dakota Environmental Cost Recovery Rider Accrued Refund 45 - 45 12 Minnesota Energy Intensive Trade Exposed Rider Accrued Refund 45 - 45 4 Other 6 75 81 174 Total Regulatory Liabilities $ 8,959 $ 224,655 $ 233,614 Net Regulatory Asset/(Liability) Position $ 5,542 $ (92,963 ) $ (87,421 ) 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 Deferred Marked-to-Market Losses 1 1,661 743 2,404 24 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 - 986 986 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 681 947 1,628 28 Debt Reacquisition Premiums 1 207 753 960 165 Deferred Income Taxes 1 - 2,423 2,423 asset lives 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 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 240 - 240 12 Minnesota SPP Transmission Cost Recovery Tracker 1 - 176 176 see below Minnesota Environmental Cost Recovery Rider Accrued Revenues 2 121 - 121 12 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 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 Refundable Fuel Clause Adjustment Revenues 121 - 121 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) | 6 Months Ended |
Jun. 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 26,750 Restricted Stock Issued to Directors 15,700 Directors Deferred Compensation 594 Retirements: Shares Withheld for Individual Income Tax Requirements (55,224 ) Common Shares Outstanding, June 30, 2019 39,754,902 |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Three Months ended June 30 Six Months ended June 30 2019 2018 2019 2018 Weighted Average Common Shares Outstanding – Basic 39,712,036 39,605,717 39,684,679 39,578,296 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 134,137 202,643 146,148 212,902 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 60,168 57,616 61,783 58,373 Nonvested Restricted Shares 9,657 10,733 15,790 19,188 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 1,833 2,360 2,099 2,617 Total Dilutive Shares 205,795 273,352 225,820 293,080 Weighted Average Common Shares Outstanding – Diluted 39,917,831 39,879,069 39,910,499 39,871,376 |
Note 6 - Share-based Payments (
Note 6 - Share-based Payments (Tables) | 6 Months Ended |
Jun. 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 June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Stock Performance Awards Granted to Executive Officers $ 1,418 $ 668 $ 2,531 $ 1,319 Restricted Stock Units Granted to Executive Officers 383 173 810 422 Restricted Stock Granted to Executive Officers - - - 16 Restricted Stock Granted to Nonemployee Directors 204 165 369 331 Restricted Stock Units Granted to Key Employees 143 101 234 165 Totals $ 2,148 $ 1,107 $ 3,944 $ 2,253 |
Note 8 - Leases (Tables)
Note 8 - Leases (Tables) | 6 Months Ended |
Jun. 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 $ 3,586 $ 16,630 $ 666 $ 769 $ 21,651 Accumulated Amortization (526 ) (1,393 ) (195 ) (64 ) (2,178 ) Net of Accumulated Amortization $ 3,060 $ 15,237 $ 471 $ 705 $ 19,473 Obligations: Current Operating Lease Liabilities $ 975 $ 2,303 $ 353 $ 153 $ 3,784 Long-Term Operating Lease Liabilities 2,336 13,019 118 611 16,084 Total Lease Liabilities $ 3,311 $ 15,322 $ 471 $ 764 $ 19,868 |
Lessee, Operating Lease, Liability, Maturity [Table Text Block] | Right-of-Use Operating Leases (in thousands) OTP Nonelectric Total 2019 $ 570 $ 2,055 $ 2,625 2020 1,115 3,872 4,987 2021 1,100 3,600 4,700 2022 207 3,465 3,672 2023 196 3,174 3,370 Beyond 2023 447 8,022 8,469 Total Minimum Obligations $ 3,635 $ 24,188 $ 27,823 Interest Component of Obligations (314 ) (4,115 ) (4,429 ) Present Value of Leases Commencing after June 30, 2019 (10 ) (3,516 ) (3,526 ) Present Value of Minimum Obligations, June 30, 2019 $ 3,311 $ 16,557 $ 19,868 |
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 167 1,725 1,892 Lease Modifications - (1,366 ) (1,366 ) Lease Obligation Payments (551 ) (992 ) (1,543 ) Interest Component of Lease Obligation Payment 86 430 516 Operating Lease Obligations, June 30, 2019 $ 3,311 $ 16,557 $ 19,868 |
Lease, Cost [Table Text Block] | Three Months Ended June 30, 2019 Six Months Ended June 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 $ 11 $ - $ 11 $ 20 $ - $ 20 Inventory 238 - 238 463 - 463 Cost of Products Sold 943 45 988 1,979 72 2,051 Electric Operation and Maintenance Expenses 64 - 64 130 - 130 Other Nonelectric Expenses 51 1 52 105 1 106 Total 1,307 $ 46 $ 1,353 $ 2,697 $ 73 $ 2,770 |
Note 10 - Short-term and Long_2
Note 10 - Short-term and Long-term Borrowings (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Line of Credit Facilities [Table Text Block] | (in thousands) Line Limit In Use on June 30, 2019 Restricted due to Outstanding Letters of Credit Available on June 30, 2019 Available on December 31, 2018 Otter Tail Corporation Credit Agreement $ 130,000 $ 13,801 $ - $ 116,199 $ 120,785 OTP Credit Agreement 170,000 22,801 8,766 138,433 160,316 Total $ 300,000 $ 36,602 $ 8,766 $ 254,632 $ 281,101 |
Schedule of Debt [Table Text Block] | June 30 , 201 9 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 22,801 $ 13,801 $ 36,602 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 438 438 Total $ 512,000 $ 80,438 $ 592,438 Less: Current Maturities net of Unamortized Debt Issuance Costs - 177 177 Unamortized Long-Term Debt Issuance Costs 1,816 382 2,198 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 510,184 $ 79,879 $ 590,063 Total Short-Term and Long-Term Debt (with current maturities) $ 532,985 $ 93,857 $ 626,842 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) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Net Benefit Costs [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 1,373 $ 1,615 2,746 $ 3,230 Interest Cost on Projected Benefit Obligation 3,603 3,363 7,206 6,726 Expected Return on Assets (5,324 ) (5,299 ) (10,649 ) (10,599 ) Amortization of Prior-Service Cost: From Regulatory Asset 2 4 3 8 From Other Comprehensive Income 1 2 - 4 - Amortization of Net Actuarial Loss: From Regulatory Asset 1,162 1,783 2,325 3,567 From Other Comprehensive Income 1 26 47 53 91 Net Periodic Pension Cost 2 $ 844 $ 1,513 $ 1,688 $ 3,023 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 336 $ 379 $ 726 $ 707 Service costs included in electric operation and maintenance expenses 1,004 1,195 1,954 2,442 Service costs included in other nonelectric expenses 33 40 66 80 Nonservice costs capitalized as regulatory assets (130 ) (24 ) (280 ) (45 ) Nonservice costs included in n onservice cost components of postretirement benefits (399 ) (77 ) (778 ) (161 ) Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 104 $ 100 $ 209 $ 200 Interest Cost on Projected Benefit Obligation 434 399 868 798 Amortization of Prior-Service Cost: From Regulatory Asset 1 4 2 8 From Other Comprehensive Income 1 4 9 8 19 Amortization of Net Actuarial Loss: From Regulatory Asset 31 67 62 134 From Other Comprehensive Income 1 88 165 175 330 Net Periodic Pension Cost 2 $ 662 $ 744 $ 1,324 $ 1,489 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 $ 25 $ 52 $ 50 Service costs included in other nonelectric expenses 78 75 157 150 Nonservice costs included in n onservice cost components of postretirement benefits 558 644 1,115 1,289 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Service Cost—Benefit Earned During the Period $ 322 $ 381 $ 643 $ 763 Interest Cost on Projected Benefit Obligation 772 646 1,542 1,291 Amortization of Net Actuarial Loss: From Regulatory Asset 392 412 785 824 From Other Comprehensive Income 1 9 11 19 21 Net Periodic Postretirement Benefit Cost 2 $ 1,495 $ 1,450 $ 2,989 $ 2,899 Effect of Medicare Part D Subsidy $ (44 ) $ (36 ) $ (89 ) $ (73 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 79 $ 89 $ 170 $ 167 Service costs included in electric operation and maintenance expenses 235 283 458 577 Service costs included in other nonelectric expenses 8 9 15 19 Nonservice costs capitalized as regulatory assets 288 251 621 468 Nonservice costs included in n onservice cost components of postretirement benefits 885 818 1,725 1,668 |
Note 12 - Fair Value of Finan_2
Note 12 - Fair Value of Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Fair Value, by Balance Sheet Grouping [Table Text Block] | June 30, 2019 December 31, 2018 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 982 $ 982 $ 861 $ 861 Short-Term Debt (36,602 ) (36,602 ) (18,599 ) (18,599 ) Long-Term Debt including Current Maturities (590,240 ) (631,747 ) (590,174 ) (601,513 ) |
Note 14 - Income Tax Expense (T
Note 14 - Income Tax Expense (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Notes Tables | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2019 2018 2019 2018 Income Before Income Taxes $ 18,769 $ 21,750 $ 50,721 $ 51,759 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) $ 4,879 $ 5,655 $ 13,187 $ 13,457 Decreases in Tax from: Differences Reversing in Excess of Federal Rates (774 ) (1,025 ) (1,757 ) (2,098 ) Excess Tax Deduction – Equity Method Stock Awards - - (827 ) (624 ) Corporate Owned Life Insurance (150 ) (17 ) (559 ) (25 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (258 ) (516 ) (516 ) Research and Development and Other Tax Credits (187 ) (180 ) (375 ) (360 ) Allowance for Funds Used During Construction – Equity (94 ) (111 ) (180 ) (278 ) Federal Production Tax Credits - (930 ) - (2,050 ) Other Comprehensive Income Deferred Tax Rate Adjustment - - - (531 ) Other Items – Net (73 ) (80 ) (2 ) (127 ) Income Tax Expense $ 3,343 $ 3,054 $ 8,971 $ 6,848 Effective Income Tax Rate 17.8 % 14.0 % 17.7 % 13.2 % |
Summary of Income Tax Contingencies [Table Text Block] | (in thousands) 2019 2018 Balance on January 1 $ 1,282 $ 684 Decreases Related to Tax Positions for Prior Years - - Increases Related to Tax Positions for Current Year 75 72 Uncertain Positions Resolved During Year (42 ) (44 ) Balance on June 30 $ 1,315 $ 712 |
Note 1 - Summary of Significa_3
Note 1 - Summary of Significant Accounting Policies (Details Textual) - USD ($) | Jan. 01, 2019 | Jun. 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 | $ 52,200,000 | ||
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 | Jun. 30, 2019 | Dec. 31, 2018 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Assets | $ 2,794 | $ 2,132 |
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | ||
Investments | 1,483 | 1,294 |
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member] | ||
Other Assets | 1,311 | 838 |
Fair Value, Inputs, Level 2 [Member] | ||
Total Assets | 8,069 | 7,484 |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | ||
Investments | 3,368 | 5,898 |
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Investments | $ 4,701 | $ 1,586 |
Note 1 - Summary of Significa_5
Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Finished Goods | $ 32,699 | $ 37,130 |
Work in Process | 19,414 | 20,393 |
Raw Material, Fuel and Supplies | 53,747 | 48,747 |
Total Inventories | $ 105,860 | $ 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 | 6 Months Ended | |
Jun. 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 | 6 Months Ended | 12 Months Ended |
Jun. 30, 2019 | Dec. 31, 2018 | |
Gross Carrying Amount | $ 22,645 | $ 22,645 |
Accumulated Amortization | 10,787 | 10,195 |
Net Carrying Amount | 11,858 | 12,450 |
Customer Relationships [Member] | ||
Gross Carrying Amount | 22,491 | 22,491 |
Accumulated Amortization | 10,693 | 10,127 |
Net Carrying Amount | $ 11,798 | $ 12,364 |
Customer Relationships [Member] | Minimum [Member] | ||
Remaining Amortization Periods (Month) | 6 months | 12 months |
Customer Relationships [Member] | Maximum [Member] | ||
Remaining Amortization Periods (Month) | 194 months | 200 months |
Other Intangible Assets [Member] | ||
Gross Carrying Amount | $ 154 | $ 154 |
Accumulated Amortization | 94 | 68 |
Net Carrying Amount | $ 60 | $ 86 |
Remaining Amortization Periods (Month) | 14 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 | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Amortization Expense – Intangible Assets | $ 296 | $ 345 | $ 592 | $ 690 |
Note 1 - Summary of Significa_9
Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands | Jun. 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 | Jun. 30, 2019 | Jun. 30, 2018 |
Transactions Related to Capital Additions not Settled in Cash | $ 16,841 | $ 11,564 |
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 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 |
Other Comprehensive Income (Loss) | $ 145 | $ 162 | $ 313 | $ (340) | ||
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) | $ 145 | $ 162 | 313 | $ (340) | |
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 | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 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% | 98.20% | 98.80% | 98.30% |
Note 2 - Business Segment Infor
Note 2 - Business Segment Information - Business Segments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Total Operating Revenues | $ 229,203 | $ 226,348 | $ 475,175 | $ 467,614 | |
Interest charges | 7,825 | 7,676 | 15,651 | 15,048 | |
Income Tax Expense | 3,343 | 3,054 | 8,971 | 6,848 | |
Net Income (Loss) | 15,426 | 18,696 | 41,750 | 44,911 | |
Assets | 2,114,944 | 2,114,944 | $ 2,052,517 | ||
Operating Segments [Member] | Electric [Member] | |||||
Regulated operating revenues | 102,244 | 103,725 | 230,353 | 226,690 | |
Interest charges | 6,625 | 6,687 | 13,266 | 13,077 | |
Income Tax Expense | 1,037 | 611 | 5,808 | 2,709 | |
Net Income (Loss) | 7,502 | 10,600 | 26,202 | 27,268 | |
Assets | 1,752,432 | 1,752,432 | 1,728,534 | ||
Operating Segments [Member] | Electric [Member] | Retail [Member] | |||||
Revenue from Contracts with Customers | 87,976 | 89,400 | 202,931 | 198,580 | |
Changes in Accrued ARP Revenues | 369 | (1,565) | (680) | (2,440) | |
Regulated operating revenues | 88,345 | 87,835 | 202,251 | 196,140 | |
Operating Segments [Member] | Electric [Member] | Electric Transmission [Member] | |||||
Revenue from Contracts with Customers | 11,469 | 11,313 | 22,331 | 23,216 | |
Operating Segments [Member] | Electric [Member] | Wholesale [Member] | |||||
Revenue from Contracts with Customers | 941 | 2,539 | 2,468 | 3,554 | |
Operating Segments [Member] | Electric [Member] | Product and Service, Other [Member] | |||||
Revenue from Contracts with Customers | 1,489 | 2,038 | 3,303 | 3,780 | |
Operating Segments [Member] | Manufacturing [Member] | |||||
Revenue from Contracts with Customers | 73,496 | 68,154 | 151,318 | 136,816 | |
Interest charges | 646 | 555 | 1,230 | 1,109 | |
Income Tax Expense | 1,149 | 1,018 | 2,603 | 2,241 | |
Net Income (Loss) | 3,990 | 3,583 | 8,832 | 7,747 | |
Assets | 211,374 | 211,374 | 187,556 | ||
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member] | |||||
Revenue from Contracts with Customers | 62,541 | 57,388 | 129,265 | 114,315 | |
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member] | |||||
Revenue from Contracts with Customers | 9,353 | 7,961 | 18,398 | 18,196 | |
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member] | |||||
Revenue from Contracts with Customers | 1,602 | 2,805 | 3,655 | 4,305 | |
Operating Segments [Member] | Plastics [Member] | |||||
Revenue from Contracts with Customers | 53,476 | 54,476 | 93,534 | 104,129 | |
Interest charges | 215 | 160 | 364 | 310 | |
Income Tax Expense | 2,044 | 2,207 | 3,373 | 4,621 | |
Net Income (Loss) | 5,792 | 6,229 | 9,521 | 13,073 | |
Assets | 104,762 | 104,762 | 91,630 | ||
Corporate and Eliminations [Member] | |||||
Interest charges | 339 | 274 | 791 | 552 | |
Income Tax Expense | (887) | (782) | (2,813) | (2,723) | |
Net Income (Loss) | (1,858) | (1,716) | (2,805) | (3,177) | |
Assets | 46,376 | 46,376 | $ 44,797 | ||
Intersegment Eliminations [Member] | |||||
Regulated operating revenues | $ (13) | $ (7) | $ (30) | $ (21) |
Note 3 - Rate and Regulatory _3
Note 3 - Rate and Regulatory Matters (Details Textual) | Jun. 28, 2019USD ($) | Jun. 24, 2019USD ($) | 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 | Mar. 31, 2019USD ($) | Jun. 30, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017 | Mar. 01, 2018USD ($) | 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 | $ 233,614,000 | $ 227,207,000 | ||||||||||||||||||||||||||
Minnesota1 [Member] | ||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 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 | |||||||||||||||||||||||||||
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 | $ 2,700,000 | ||||||||||||||||||||||||||
Contract with Customer, Refund Liability, Total | 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 | 8.61% | |||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.74% | |||||||||||||||||||||||||||
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] | Minnesota1 [Member] | ||||||||||||||||||||||||||||
Loss Contingency, Estimate of Possible Loss | 2,900,000 | |||||||||||||||||||||||||||
Environmental Cost Recovery Rider Rate | 0.00% | |||||||||||||||||||||||||||
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] | 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 | 163 | |||||||||||||||||||||||||||
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 | $ 19,600,000 | |||||||||||||||||||||||||||
Expected Project Cost | 158,000,000 | |||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Merricourt Project [Member] | EDF [Member] | ||||||||||||||||||||||||||||
Expanded Capacity of Projects (MW) | 150 | |||||||||||||||||||||||||||
Expected Project Cost | 270,000,000 | |||||||||||||||||||||||||||
Asset Purchase Agreement, Purchase Price | $ 37,700,000 | $ 34,700,000 | ||||||||||||||||||||||||||
Turnkey Engineering, Procurement and Construction Services Agreement, Costs | $ 200,500,000 | |||||||||||||||||||||||||||
Current Project Cost | $ 5,600,000 |
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 | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | ||
Revenues recorded under rate riders | $ 5,314 | $ 8,512 | $ 13,459 | $ 18,628 | |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Revenues recorded under rate riders | [1] | 2,618 | 2,368 | 4,770 | 4,884 |
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | |||||
Revenues recorded under rate riders | 1,317 | 659 | 2,633 | 1,184 | |
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | (56) | (458) | 585 | (487) | |
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 0 | (18) | (1) | (49) | |
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | |||||
Revenues recorded under rate riders | (93) | 2,079 | 636 | 4,046 | |
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 874 | 1,165 | 2,646 | 3,227 | |
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | (12) | 1,830 | 563 | 3,651 | |
North Dakota 1 [Member] | Generation Cost Recovery [Member] | |||||
Revenues recorded under rate riders | 222 | 0 | 470 | 0 | |
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Revenues recorded under rate riders | 96 | 122 | 340 | 351 | |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 371 | 250 | 844 | 786 | |
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | $ (23) | $ 515 | $ (27) | $ 1,035 | |
[1] | Includes MNCIP costs recovered in base rates. |
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 | 6 Months Ended | |||
Jun. 30, 2019USD ($) | Jun. 30, 2018USD ($) | Jun. 30, 2019USD ($)kWh | Jun. 30, 2018USD ($) | ||
Annual Revenue | $ 5,314 | $ 8,512 | $ 13,459 | $ 18,628 | |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Annual Revenue | [1] | 2,618 | 2,368 | $ 4,770 | 4,884 |
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2018 Incentive and Cost Recovery [Member] | |||||
R - Request Date | Apr. 1, 2019 | ||||
Effective Date Requested or Approved | Oct. 1, 2019 | ||||
Annual Revenue | $ 11,926 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00710 | ||||
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member] | |||||
Effective Date Requested or Approved | Nov. 1, 2018 | ||||
Annual Revenue | $ 10,283 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00600 | ||||
A - Approval Date | Oct. 4, 2018 | ||||
Minnesota1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member] | |||||
Effective Date Requested or Approved | Oct. 1, 2017 | ||||
Annual Revenue | $ 9,868 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | ||||
A - Approval Date | Sep. 15, 2017 | ||||
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Annual Revenue | (56) | (458) | $ 585 | (487) | |
Minnesota1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Annual Update - Scenario A [Member] | |||||
R - Request Date | Nov. 30, 2018 | ||||
Effective Date Requested or Approved | Jun. 1, 2019 | ||||
Annual Revenue | $ 6,475 | ||||
Rate | Various | ||||
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] | |||||
Effective Date Requested or Approved | Nov. 1, 2017 | ||||
Annual Revenue | $ (3,311) | ||||
A - Approval Date | Oct. 30, 2017 | ||||
Rate | Various | ||||
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Annual Revenue | 0 | (18) | $ (1) | (49) | |
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | |||||
Effective Date Requested or Approved | Nov. 1, 2017 | ||||
Annual Revenue | $ (1,943) | ||||
A - Approval Date | Oct. 30, 2017 | ||||
Rate of base | (0.935%) | ||||
Minnesota1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member] | |||||
Effective Date Requested or Approved | Dec. 1, 2018 | ||||
Annual Revenue | $ 0 | ||||
A - Approval Date | Nov. 29, 2018 | ||||
Rate of base | 0.00% | ||||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | |||||
Annual Revenue | 1,317 | 659 | $ 2,633 | 1,184 | |
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | |||||
Effective Date Requested or Approved | Nov. 1, 2017 | ||||
Annual Revenue | $ 1,279 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00049 | ||||
A - Approval Date | Oct. 30, 2017 | ||||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member] | |||||
Effective Date Requested or Approved | Nov. 1, 2018 | ||||
Annual Revenue | $ 5,886 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00219 | ||||
A - Approval Date | Aug. 29, 2018 | ||||
Minnesota1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member] | |||||
R - Request Date | Jun. 21, 2019 | ||||
Effective Date Requested or Approved | Nov. 1, 2019 | ||||
Annual Revenue | $ 12,571 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00469 | ||||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Annual Revenue | 874 | 1,165 | $ 2,646 | 3,227 | |
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2018 | ||||
Annual Revenue | $ 7,469 | ||||
A - Approval Date | Feb. 27, 2018 | ||||
Rate | Various | ||||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Supplemental Update [Member] | |||||
Effective Date Requested or Approved | Feb. 1, 2019 | ||||
Annual Revenue | $ 4,801 | ||||
A - Approval Date | Dec. 6, 2018 | ||||
Rate | Various | ||||
North Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | |||||
Effective Date Requested or Approved | Jan. 1, 2018 | ||||
Annual Revenue | $ 7,959 | ||||
A - Approval Date | Nov. 29, 2017 | ||||
Rate | Various | ||||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Annual Revenue | (12) | 1,830 | $ 563 | 3,651 | |
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | |||||
Effective Date Requested or Approved | Jan. 1, 2018 | ||||
Annual Revenue | $ 8,537 | ||||
A - Approval Date | Dec. 20, 2017 | ||||
Rate of base | 6.629% | ||||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member] | |||||
Effective Date Requested or Approved | Feb. 1, 2019 | ||||
Annual Revenue | $ (378) | ||||
A - Approval Date | Dec. 19, 2018 | ||||
Rate of base | (0.31%) | ||||
North Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2018 | ||||
Annual Revenue | $ 7,718 | ||||
A - Approval Date | Feb. 27, 2018 | ||||
Rate of base | 5.593% | ||||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | |||||
Annual Revenue | (93) | 2,079 | $ 636 | 4,046 | |
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | |||||
Effective Date Requested or Approved | Jan. 1, 2018 | ||||
Annual Revenue | $ 9,989 | ||||
A - Approval Date | Dec. 20, 2017 | ||||
Rate of base | 7.756% | ||||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2019 Annual Update [Member] | |||||
Effective Date Requested or Approved | Jun. 1, 2019 | ||||
Annual Revenue | $ (235) | ||||
A - Approval Date | May 1, 2019 | ||||
Rate of base | (0.224%) | ||||
North Dakota 1 [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2018 | ||||
Annual Revenue | $ 9,650 | ||||
A - Approval Date | Feb. 27, 2018 | ||||
Rate of base | 7.493% | ||||
North Dakota 1 [Member] | Generation Cost Recovery [Member] | |||||
Annual Revenue | 222 | 0 | $ 470 | 0 | |
North Dakota 1 [Member] | Generation Cost Recovery [Member] | The 2019 Initial Request [Member] | |||||
Effective Date Requested or Approved | Jul. 1, 2019 | ||||
Annual Revenue | $ 2,720 | ||||
A - Approval Date | May 15, 2019 | ||||
Rate of base | 2.547% | ||||
South Dakota 1 [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Annual Revenue | 96 | 122 | $ 340 | 351 | |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | |||||
Annual Revenue | 371 | 250 | $ 844 | 786 | |
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Annual Update [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2019 | ||||
Annual Revenue | $ 1,638 | ||||
A - Approval Date | Feb. 20, 2019 | ||||
Rate | Various | ||||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2018 | ||||
Annual Revenue | $ 1,779 | ||||
A - Approval Date | Feb. 28, 2018 | ||||
Rate | Various | ||||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2019 Rate Reset [Member] | |||||
R - Request Date | Jul. 31, 2019 | ||||
Effective Date Requested or Approved | Oct. 1, 2019 | ||||
Annual Revenue | $ 2,050 | ||||
Rate | Various | ||||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member] | |||||
Effective Date Requested or Approved | Oct. 18, 2018 | ||||
Annual Revenue | $ 1,171 | ||||
A - Approval Date | Oct. 18, 2018 | ||||
Rate | Various | ||||
South Dakota 1 [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | |||||
Effective Date Requested or Approved | Mar. 1, 2017 | ||||
Annual Revenue | $ 2,053 | ||||
A - Approval Date | Feb. 17, 2017 | ||||
Rate | Various | ||||
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | |||||
Annual Revenue | $ (23) | $ 515 | $ (27) | $ 1,035 | |
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | |||||
Effective Date Requested or Approved | Nov. 1, 2017 | ||||
Annual Revenue | $ 2,082 | ||||
Rate rider rate (Kilowatt-Hour) | kWh | 0.00483 | ||||
A - Approval Date | Oct. 13, 2017 | ||||
South Dakota 1 [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Interim Rate Reset [Member] | |||||
Effective Date Requested or Approved | Oct. 18, 2018 | ||||
Annual Revenue | $ (189) | ||||
Rate rider rate (Kilowatt-Hour) | kWh | (0.00075) | ||||
A - Approval Date | Oct. 18, 2018 | ||||
South Dakota 1 [Member] | Phase-In Rate Plan [Member] | The 2019 Initial Request [Member] | |||||
R - Request Date | May 31, 2019 | ||||
Effective Date Requested or Approved | Sep. 1, 2019 | ||||
Annual Revenue | $ 1,027 | ||||
Rate of base | 3.942% | ||||
[1] | Includes MNCIP costs recovered in base rates. |
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 | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2019 | Dec. 31, 2018 | ||
Regulatory Assets - Current | $ 14,501 | $ 17,225 | |
Regulatory Assets - Long -Term | 131,692 | 135,257 | |
Regulatory Assets - Total | 146,193 | 152,482 | |
Regulatory Liabilities - Current | 8,959 | 738 | |
Regulatory Liabilities - Long -Term | 224,655 | 226,469 | |
Regulatory Liabilities, Total | 233,614 | 227,207 | |
Net Regulatory Asset Position - Current | 5,542 | 16,487 | |
Net Regulatory Asset Position - Long-Term | (92,963) | (91,212) | |
Net Regulatory Asset/(Liability) Position | (87,421) | (74,725) | |
Deferred Income Taxes [Member] | |||
Regulatory Liabilities - Current | 0 | 0 | |
Regulatory Liabilities - Long -Term | 140,226 | 142,779 | |
Regulatory Liabilities, Total | $ 140,226 | $ 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 | 83,977 | 83,229 | |
Regulatory Liabilities, Total | $ 83,977 | $ 83,229 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Refundable Fuel Clause Adjustment Revenues - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 5,087 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 5,087 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
North Dakota Renewable Resource Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 725 | $ 177 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 725 | $ 177 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | 12 months | |
Refundable Fuel Clause Adjustment Revenues – North Dakota [Member] | |||
Regulatory Liabilities - Current | $ 1,676 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 1,676 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 391 | $ 60 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 391 | $ 60 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | 12 months | |
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 0 | $ 0 | |
Regulatory Liabilities - Long -Term | 284 | 166 | |
Regulatory Liabilities, Total | $ 284 | $ 166 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | see below | |
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 614 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 614 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Liabilities - Current | $ 94 | $ 0 | |
Regulatory Liabilities - Long -Term | 93 | 187 | |
Regulatory Liabilities, Total | $ 187 | $ 187 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 18 months | 24 months | |
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 146 | $ 168 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 146 | $ 168 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | 12 months | |
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 45 | $ 207 | |
Regulatory Liabilities - Long -Term | 0 | 0 | |
Regulatory Liabilities, Total | $ 45 | $ 207 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | 12 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 | ||
Other [Member] | |||
Regulatory Liabilities - Current | $ 6 | $ 5 | |
Regulatory Liabilities - Long -Term | 75 | 108 | |
Regulatory Liabilities, Total | $ 81 | $ 113 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 174 months | 180 months | |
Refundable Fuel Clause Adjustment Revenues – South Dakota [Member] | |||
Regulatory Liabilities - Current | $ 130 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 130 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 12 months | ||
Minnesota Energy Intensive Trade Exposed Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 45 | ||
Regulatory Liabilities - Long -Term | 0 | ||
Regulatory Liabilities, Total | $ 45 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 4 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] | 115,246 | 118,433 |
Regulatory Assets - Total | [1] | $ 121,601 | $ 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] | 7,436 | 7,169 |
Regulatory Assets - Total | [1] | $ 7,436 | $ 7,169 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Conservation Improvement Program Costs and Incentives [Member] | |||
Regulatory Assets - Current | [2] | $ 1,861 | $ 5,995 |
Regulatory Assets - Long -Term | [2] | 4,659 | 3,285 |
Regulatory Assets - Total | [2] | $ 6,520 | $ 9,280 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 27 months | 21 months |
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 2,637 | $ 444 |
Regulatory Assets - Long -Term | [2] | 0 | 0 |
Regulatory Assets - Total | [2] | $ 2,637 | $ 444 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | 12 months |
Deferred Marked-to-Market Losses [Member] | |||
Regulatory Assets - Current | [1] | $ 1,202 | $ 1,661 |
Regulatory Assets - Long -Term | [1] | 372 | 743 |
Regulatory Assets - Total | [1] | $ 1,574 | $ 2,404 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 18 months | 24 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] | 1,359 | 986 |
Regulatory Assets - Total | [1] | $ 1,359 | $ 986 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Big Stone II Unrecovered Project Costs - Minnesota [Member] | |||
Regulatory Assets - Current | [1] | $ 698 | $ 681 |
Regulatory Assets - Long -Term | [1] | 590 | 947 |
Regulatory Assets - Total | [1] | $ 1,288 | $ 1,628 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 22 months | 28 months |
Debt Reacquisition Premiums [Member] | |||
Regulatory Assets - Current | [1] | $ 203 | $ 207 |
Regulatory Assets - Long -Term | [1] | 649 | 753 |
Regulatory Assets - Total | [1] | $ 852 | $ 960 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 159 months | 165 months |
Deferred Income Taxes [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | $ 0 |
Regulatory Assets - Long -Term | [1] | 701 | 2,423 |
Regulatory Assets - Total | [1] | $ 701 | $ 2,423 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
North Dakota Generation Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 470 | |
Regulatory Assets - Long -Term | [2] | 0 | |
Regulatory Assets - Total | [2] | $ 470 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | |
South Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 455 | $ 178 |
Regulatory Assets - Long -Term | [1] | 0 | 0 |
Regulatory Assets - Total | [1] | $ 455 | $ 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] | 263 | 342 |
Regulatory Assets - Total | [1] | $ 379 | $ 442 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 39 months | 53 months |
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 377 | $ 455 |
Regulatory Assets - Long -Term | [1] | 0 | 0 |
Regulatory Assets - Total | [1] | $ 377 | $ 455 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 12 months | 12 months |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Assets - Current | [1] | $ 120 | $ 240 |
Regulatory Assets - Long -Term | [1] | 222 | 0 |
Regulatory Assets - Total | [1] | $ 342 | $ 240 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 30 months | 12 months |
Minnesota SPP Transmission Cost Recovery Tracker [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | $ 0 |
Regulatory Assets - Long -Term | [1] | 148 | 176 |
Regulatory Assets - Total | [1] | $ 148 | $ 176 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
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] | 12 months | 12 months |
Deferred Lease Expenses [Member] | |||
Regulatory Assets - Current | [1] | $ 0 | |
Regulatory Assets - Long -Term | [1] | 47 | |
Regulatory Assets - Total | [1] | $ 47 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 45 months | |
Minnesota Renewable Resource Recovery Rider, Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 3 | $ 452 |
Regulatory Assets - Long -Term | [2] | 0 | 0 |
Regulatory Assets - Total | [2] | $ 3 | $ 452 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 12 months | 12 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 | |
[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) | 6 Months Ended |
Jun. 30, 2019shares | |
Common Shares Outstanding, beginning balance (in shares) | 39,664,884 |
Vesting of Restricted Stock Units (in shares) | 26,750 |
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) | 39,754,902 |
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 | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Weighted Average Common Shares Outstanding – Basic (in shares) | 39,712,036 | 39,605,717 | 39,684,679 | 39,578,296 |
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares) | 134,137 | 202,643 | 146,148 | 212,902 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares) | 60,168 | 57,616 | 61,783 | 58,373 |
Nonvested Restricted Shares (in shares) | 9,657 | 10,733 | 15,790 | 19,188 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares) | 1,833 | 2,360 | 2,099 | 2,617 |
Total Dilutive Shares (in shares) | 205,795 | 273,352 | 225,820 | 293,080 |
Weighted Average Common Shares Outstanding – Diluted (in shares) | 39,917,831 | 39,879,069 | 39,910,499 | 39,871,376 |
Note 6 - Share-based Payments_2
Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions | Feb. 13, 2019 | Jul. 31, 2019 | Jun. 30, 2019 |
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount, Total | $ 5.5 | ||
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition | 2 years 3 months 18 days | ||
Subsequent Event [Member] | |||
Employee Stock Purchase Plan, Employee Discount | 15.00% | ||
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) | 6 Months Ended |
Jun. 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 | 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 | 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 | 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] | 6 Months Ended |
Jun. 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 | 10.00% |
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 | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Stock compensation expense | $ 2,148 | $ 1,107 | $ 3,944 | $ 2,253 |
Stock Performance Awards [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 1,418 | 668 | 2,531 | 1,319 |
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 383 | 173 | 810 | 422 |
Restricted Stock Units (RSUs) [Member] | Key Employee [Member] | ||||
Stock compensation expense | 143 | 101 | 234 | 165 |
Restricted Stock [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 0 | 0 | 0 | 16 |
Restricted Stock [Member] | Nonemployee Directors [Member] | ||||
Stock compensation expense | $ 204 | $ 165 | $ 369 | $ 331 |
Note 7 - Retained Earnings an_2
Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($) | Jul. 19, 2019 | Jun. 30, 2019 | Dec. 31, 2018 |
Capitalization, Long-term Debt and Equity, Total | $ 1,334,368,000 | $ 1,318,865,000 | |
Otter Tail Power Company [Member] | |||
Equity to Total Capitalization Ratio | 52.80% | ||
Net Assets Restricted from Distribution | $ 490,000,000 | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Minimum [Member] | |||
Public Utilities, Requested Equity Capital Structure, Percentage | 47.90% | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Minimum [Member] | Subsequent Event [Member] | |||
Public Utilities, Approved Equity Capital Structure, Percentage | 46.00% | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member] | |||
Public Utilities, Requested Equity Capital Structure, Percentage | 58.50% | ||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Maximum [Member] | Subsequent Event [Member] | |||
Public Utilities, Approved Equity Capital Structure, Percentage | 56.20% | ||
Capitalization, Long-term Debt and Equity, Total | $ 1,331,302,000 |
Note 8 - Leases (Details Textua
Note 8 - Leases (Details Textual) - USD ($) $ in Thousands | Jun. 30, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Operating Lease, Liability, Total | $ 19,868 | $ 20,369 | |
Operating Lease, Right-of-Use Asset | $ 19,473 | $ 0 | |
Operating Lease, Weighted Average Remaining Lease Term | 5 years 9 months 18 days | ||
Operating Lease, Weighted Average Discount Rate, Percent | 5.00% | ||
Lease of Warehouse by T.O. Plastics [Member] | |||
Lessee, Operating Lease, Term of Contract | 10 years | ||
Lease for 20 Coal Rail Cars [Member] | |||
Lessee, Operating Lease, Term of Contract | 15 years | ||
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, Liability, Total | $ 20,000 | ||
Operating Lease, Right-of-Use Asset | $ 20,000 |
Note 8 - Leases - Lease Assets
Note 8 - Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Gross | $ 21,651 | |
Accumulated Amortization | (2,178) | |
Net of Accumulated Amortization | 19,473 | $ 0 |
Current Operating Lease Liabilities | 3,784 | 0 |
Long-Term Operating Lease Liabilities | 16,084 | 0 |
Total Lease Liabilities | 19,868 | $ 20,369 |
Electric [Member] | ||
Gross | 3,586 | |
Accumulated Amortization | (526) | |
Net of Accumulated Amortization | 3,060 | |
Current Operating Lease Liabilities | 975 | |
Long-Term Operating Lease Liabilities | 2,336 | |
Total Lease Liabilities | 3,311 | |
Manufacturing [Member] | ||
Gross | 16,630 | |
Accumulated Amortization | (1,393) | |
Net of Accumulated Amortization | 15,237 | |
Current Operating Lease Liabilities | 2,303 | |
Long-Term Operating Lease Liabilities | 13,019 | |
Total Lease Liabilities | 15,322 | |
Plastics [Member] | ||
Gross | 666 | |
Accumulated Amortization | (195) | |
Net of Accumulated Amortization | 471 | |
Current Operating Lease Liabilities | 353 | |
Long-Term Operating Lease Liabilities | 118 | |
Total Lease Liabilities | 471 | |
Corporate Segment [Member] | ||
Gross | 769 | |
Accumulated Amortization | (64) | |
Net of Accumulated Amortization | 705 | |
Current Operating Lease Liabilities | 153 | |
Long-Term Operating Lease Liabilities | 611 | |
Total Lease Liabilities | $ 764 |
Note 8 - Leases - Lease Obligat
Note 8 - Leases - Lease Obligations (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
2019 | $ 2,625 | |
2020 | 4,987 | |
2021 | 4,700 | |
2022 | 3,672 | |
2023 | 3,370 | |
Beyond 2023 | 8,469 | |
Total Minimum Obligations | 27,823 | |
Interest Component of Obligations | (4,429) | |
Present Value of Leases Commencing after June 30, 2019 | (3,526) | |
Present Value of Minimum Obligations, June 30, 2019 | 19,868 | $ 20,369 |
OTP [Member] | ||
2019 | 570 | |
2020 | 1,115 | |
2021 | 1,100 | |
2022 | 207 | |
2023 | 196 | |
Beyond 2023 | 447 | |
Total Minimum Obligations | 3,635 | |
Interest Component of Obligations | (314) | |
Present Value of Leases Commencing after June 30, 2019 | (10) | |
Present Value of Minimum Obligations, June 30, 2019 | 3,311 | 3,609 |
Nonelectric Companies [Member] | ||
2019 | 2,055 | |
2020 | 3,872 | |
2021 | 3,600 | |
2022 | 3,465 | |
2023 | 3,174 | |
Beyond 2023 | 8,022 | |
Total Minimum Obligations | 24,188 | |
Interest Component of Obligations | (4,115) | |
Present Value of Leases Commencing after June 30, 2019 | (3,516) | |
Present Value of Minimum Obligations, June 30, 2019 | $ 16,557 | $ 16,760 |
Note 8 - Leases - Operating Lea
Note 8 - Leases - Operating Lease Obligation (Details) $ in Thousands | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Operating Lease Obligations, beginning balance | $ 20,369 |
Non-cash Acquisition of Right-of-Use Assets | 1,892 |
Lease Modifications | (1,366) |
Lease Obligation Payments | (1,543) |
Interest Component of Lease Obligation Payment | 516 |
Operating Lease Obligations, ending balance | 19,868 |
OTP [Member] | |
Operating Lease Obligations, beginning balance | 3,609 |
Non-cash Acquisition of Right-of-Use Assets | 167 |
Lease Modifications | 0 |
Lease Obligation Payments | (551) |
Interest Component of Lease Obligation Payment | 86 |
Operating Lease Obligations, ending balance | 3,311 |
Nonelectric Companies [Member] | |
Operating Lease Obligations, beginning balance | 16,760 |
Non-cash Acquisition of Right-of-Use Assets | 1,725 |
Lease Modifications | (1,366) |
Lease Obligation Payments | (992) |
Interest Component of Lease Obligation Payment | 430 |
Operating Lease Obligations, ending balance | $ 16,557 |
Note 8 - Leases - Allocation of
Note 8 - Leases - Allocation of Lease Costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019 | Jun. 30, 2019 | |
Operating lease cost | $ 1,307 | $ 2,697 |
Variable lease cost | 46 | 73 |
Total lease cost | 1,353 | 2,770 |
Fixed Assets [Member] | ||
Operating lease cost | 11 | 20 |
Variable lease cost | 0 | 0 |
Total lease cost | 11 | 20 |
Production Fuel [Member] | ||
Operating lease cost | 238 | 463 |
Variable lease cost | 0 | 0 |
Total lease cost | 238 | 463 |
Cost of Sales [Member] | ||
Operating lease cost | 943 | 1,979 |
Variable lease cost | 45 | 72 |
Total lease cost | 988 | 2,051 |
Electric Operating and Maintenance Expenses [Member] | ||
Operating lease cost | 64 | 130 |
Variable lease cost | 0 | 0 |
Total lease cost | 64 | 130 |
Other Nonelectric Expenses [member] | ||
Operating lease cost | 51 | 105 |
Variable lease cost | 1 | 1 |
Total lease cost | $ 52 | $ 106 |
Note 9 - Commitments and Cont_2
Note 9 - Commitments and Contingencies (Details Textual) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2019 | 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] | ||
Long-term Purchase Commitment, Amount | $ 77.3 | $ 64.5 |
Contract Expiration Year | 2021 | |
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] | ||
Long-term Purchase Commitment, Amount | $ 10.5 | |
Contract Expiration Year | 2034 | |
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member] | ||
Long-term Purchase Commitment, Amount | $ 4.1 | $ 5 |
Note 10 - Short-term and Long_3
Note 10 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Line Limit | $ 300,000 | |
In Use | 36,602 | |
Restricted due to Outstanding Letters of Credit | 8,766 | |
Available | 254,632 | $ 281,101 |
Otter Tail Corporation Credit Agreement [Member] | ||
Line Limit | 130,000 | |
In Use | 13,801 | |
Restricted due to Outstanding Letters of Credit | 0 | |
Available | 116,199 | 120,785 |
OTP Credit Agreement [Member] | ||
Line Limit | 170,000 | |
In Use | 22,801 | |
Restricted due to Outstanding Letters of Credit | 8,766 | |
Available | $ 138,433 | $ 160,316 |
Note 10 - Short-term and Long_4
Note 10 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Short-Term Debt | $ 36,602 | $ 18,599 |
Long-Term Debt | 592,438 | 592,523 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 177 | 172 |
Unamortized Long-Term Debt Issuance Costs | 2,198 | 2,349 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 590,063 | 590,002 |
Total Short-Term and Long-Term Debt (with current maturities) | 626,842 | 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 | 438 | 523 |
Otter Tail Power Company [Member] | ||
Short-Term Debt | 22,801 | 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 | 1,816 | 1,942 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 510,184 | 510,058 |
Total Short-Term and Long-Term Debt (with current maturities) | 532,985 | 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 | 13,801 | 9,215 |
Long-Term Debt | 80,438 | 80,523 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 177 | 172 |
Unamortized Long-Term Debt Issuance Costs | 382 | 407 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 79,879 | 79,944 |
Total Short-Term and Long-Term Debt (with current maturities) | 93,857 | 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 | $ 438 | $ 523 |
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) (Parentheticals) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2019 | Dec. 31, 2018 | |
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt, Interest Rate | 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] | ||
Long-Term Debt, Interest Rate | 4.63% | 4.63% |
Long-Term Debt, Due Date | Dec. 1, 2021 | Dec. 1, 2021 |
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Long-Term Debt, Interest Rate | 6.15% | 6.15% |
Long-Term Debt, Due Date | Aug. 20, 2022 | Aug. 20, 2022 |
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Long-Term Debt, Interest Rate | 6.37% | 6.37% |
Long-Term Debt, Due Date | Aug. 20, 2027 | Aug. 20, 2027 |
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Long-Term Debt, Interest Rate | 4.68% | 4.68% |
Long-Term Debt, Due Date | Feb. 27, 2029 | Feb. 27, 2029 |
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Long-Term Debt, Interest Rate | 6.47% | 6.47% |
Long-Term Debt, Due Date | Aug. 20, 2037 | Aug. 20, 2037 |
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Long-Term Debt, Interest Rate | 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] | ||
Long-Term Debt, Interest Rate | 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] | ||
Long-Term Debt, Interest Rate | 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) $ in Millions | 1 Months Ended |
Jan. 31, 2019USD ($) | |
Pension Plan [Member] | |
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 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 | 6 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | ||
Pension Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | $ 1,373 | $ 1,615 | $ 2,746 | $ 3,230 | |
Interest Cost on Projected Benefit Obligation | 3,603 | 3,363 | 7,206 | 6,726 | |
Expected Return on Assets | (5,324) | (5,299) | (10,649) | (10,599) | |
From Regulatory Asset | 2 | 4 | 3 | 8 | |
From Other Comprehensive Income | [1] | 2 | 0 | 4 | 0 |
From Regulatory Asset | 1,162 | 1,783 | 2,325 | 3,567 | |
From Other Comprehensive Income | [1] | 26 | 47 | 53 | 91 |
Net Periodic Pension Cost | [2] | 844 | 1,513 | 1,688 | 3,023 |
From Other Comprehensive Income | [1] | 26 | 47 | 53 | 91 |
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 336 | 379 | 726 | 707 | |
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 1,004 | 1,195 | 1,954 | 2,442 | |
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 33 | 40 | 66 | 80 | |
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | (130) | (24) | (280) | (45) | |
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | (399) | (77) | (778) | (161) | |
Executive Survivor and Supplemental Retirement Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 104 | 100 | 209 | 200 | |
Interest Cost on Projected Benefit Obligation | 434 | 399 | 868 | 798 | |
From Regulatory Asset | 1 | 4 | 2 | 8 | |
From Other Comprehensive Income | [3] | 4 | 9 | 8 | 19 |
From Regulatory Asset | 31 | 67 | 62 | 134 | |
From Other Comprehensive Income | [3] | 88 | 165 | 175 | 330 |
Net Periodic Pension Cost | [4] | 662 | 744 | 1,324 | 1,489 |
From Other Comprehensive Income | [3] | 88 | 165 | 175 | 330 |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 26 | 25 | 52 | 50 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 78 | 75 | 157 | 150 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | 558 | 644 | 1,115 | 1,289 | |
Other Postretirement Benefits Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 322 | 381 | 643 | 763 | |
Interest Cost on Projected Benefit Obligation | 772 | 646 | 1,542 | 1,291 | |
From Regulatory Asset | 392 | 412 | 785 | 824 | |
From Other Comprehensive Income | [1] | 9 | 11 | 19 | 21 |
Net Periodic Pension Cost | [5] | 1,495 | 1,450 | 2,989 | 2,899 |
From Other Comprehensive Income | [1] | 9 | 11 | 19 | 21 |
Effect of Medicare Part D Subsidy | (44) | (36) | (89) | (73) | |
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 79 | 89 | 170 | 167 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 235 | 283 | 458 | 577 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 8 | 9 | 15 | 19 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | 288 | 251 | 621 | 468 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | $ 885 | $ 818 | $ 1,725 | $ 1,668 | |
[1] | Corporate cost included in nonservice cost components of postretirement benefits. | ||||
[2] | Allocation of Costs: Costs included in OTP capital expenditures $ 336 $ 379 $ 726 $ 707 Service costs included in electric operation and maintenance expenses 1,004 1,195 1,954 2,442 Service costs included in other nonelectric expenses 33 40 66 80 Nonservice costs capitalized as regulatory assets (130 ) (24 ) (280 ) (45 ) Nonservice costs included in nonservice cost components of postretirement benefits (399 ) (77 ) (778 ) (161 ) | ||||
[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 $ 25 $ 52 $ 50 Service costs included in other nonelectric expenses 78 75 157 150 Nonservice costs included in nonservice cost components of postretirement benefits 558 644 1,115 1,289 | ||||
[5] | Allocation of Costs: Costs included in OTP capital expenditures $ 79 $ 89 $ 170 $ 167 Service costs included in electric operation and maintenance expenses 235 283 458 577 Service costs included in other nonelectric expenses 8 9 15 19 Nonservice costs capitalized as regulatory assets 288 251 621 468 Nonservice costs included in nonservice cost components of postretirement benefits 885 818 1,725 1,668 |
Note 12 - Fair Value of Finan_3
Note 12 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member] | 6 Months Ended | 12 Months Ended |
Jun. 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 | Jun. 30, 2019 | Dec. 31, 2018 |
Reported Value Measurement [Member] | ||
Cash and Cash Equivalents | $ 982 | $ 861 |
Short-Term Debt | (36,602) | (18,599) |
Long-Term Debt including Current Maturities | (590,240) | (590,174) |
Estimate of Fair Value Measurement [Member] | ||
Cash and Cash Equivalents | 982 | 861 |
Short-Term Debt | (36,602) | (18,599) |
Long-Term Debt including Current Maturities | $ (631,747) | $ (601,513) |
Note 14 - Income Tax Expense (D
Note 14 - Income Tax Expense (Details Textual) $ in Thousands | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Period for Unrecognized Tax Benefits Not Expected Change | 12 months |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ 0 |
Note 14 - Income Tax Expense -
Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Income Before Income Taxes | $ 18,769 | $ 21,750 | $ 50,721 | $ 51,759 |
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26%) | 4,879 | 5,655 | 13,187 | 13,457 |
Differences Reversing in Excess of Federal Rates | (774) | (1,025) | (1,757) | (2,098) |
Excess Tax Deduction – Equity Method Stock Awards | 0 | 0 | (827) | (624) |
Corporate Owned Life Insurance | (150) | (17) | (559) | (25) |
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258) | (258) | (516) | (516) |
Research and Development and Other Tax Credits | (187) | (180) | (375) | (360) |
Allowance for Funds Used During Construction – Equity | (94) | (111) | (180) | (278) |
Federal Production Tax Credits | 0 | (930) | 0 | (2,050) |
Other Comprehensive Income Deferred Tax Rate Adjustment | 0 | 0 | 0 | (531) |
Other Items – Net | (73) | (80) | (2) | (127) |
Income Tax Expense | $ 3,343 | $ 3,054 | $ 8,971 | $ 6,848 |
Effective Income Tax Rate | 17.80% | 14.00% | 17.70% | 13.20% |
Note 14 - Income Tax Expense _2
Note 14 - Income Tax Expense - Effective Income Tax Rate (Details) (Parentheticals) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 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 | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Balance, beginning | $ 1,282 | $ 684 |
Decreases Related to Tax Positions for Prior Years | 0 | 0 |
Increases Related to Tax Positions for Current Year | 75 | 72 |
Uncertain Positions Resolved During Year | (42) | (44) |
Balance, ending | $ 1,315 | $ 712 |