Document And Entity Information
Document And Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Jul. 31, 2018 | |
Document Information [Line Items] | ||
Entity Registrant Name | Otter Tail Corp | |
Entity Central Index Key | 1,466,593 | |
Trading Symbol | ottr | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Current Reporting Status | Yes | |
Entity Voluntary Filers | No | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Common Stock, Shares Outstanding (in shares) | 39,664,883 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false |
Consolidated Balance Sheets (Cu
Consolidated Balance Sheets (Current Period Not Audited) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and Cash Equivalents | $ 1,036 | $ 16,216 |
Accounts Receivable: | ||
Trade—Net | 91,780 | 68,466 |
Other | 10,224 | 7,761 |
Inventories | 90,435 | 88,034 |
Unbilled Receivables | 18,278 | 22,427 |
Income Taxes Receivable | 1,181 | |
Regulatory Assets | 17,914 | 22,551 |
Other | 9,574 | 12,491 |
Total Current Assets | 239,241 | 239,127 |
Investments | 8,649 | 8,629 |
Other Assets | 36,519 | 36,006 |
Goodwill | 37,572 | 37,572 |
Other Intangibles—Net | 13,075 | 13,765 |
Regulatory Assets | 123,631 | 129,576 |
Plant | ||
Electric Plant in Service | 1,993,738 | 1,981,018 |
Nonelectric Operations | 223,323 | 216,937 |
Construction Work in Progress | 168,372 | 141,067 |
Total Gross Plant | 2,385,433 | 2,339,022 |
Less Accumulated Depreciation and Amortization | 832,873 | 799,419 |
Net Plant | 1,552,560 | 1,539,603 |
Total Assets | 2,011,247 | 2,004,278 |
Current Liabilities | ||
Short-Term Debt | 20,977 | 112,371 |
Current Maturities of Long-Term Debt | 167 | 186 |
Accounts Payable | 95,082 | 84,185 |
Accrued Salaries and Wages | 18,460 | 21,534 |
Accrued Federal and State Income Taxes | 673 | |
Other Accrued Taxes | 10,963 | 16,808 |
Regulatory Liabilities | 7,248 | 9,688 |
Other Accrued Liabilities | 12,665 | 11,389 |
Liabilities of Discontinued Operations | 492 | |
Total Current Liabilities | 166,235 | 256,653 |
Pensions Benefit Liability | 89,424 | 109,708 |
Other Postretirement Benefits Liability | 70,203 | 69,774 |
Other Noncurrent Liabilities | 25,060 | 22,769 |
Commitments and Contingencies (note 8) | ||
Deferred Credits | ||
Deferred Income Taxes | 104,382 | 100,501 |
Deferred Tax Credits | 20,676 | 21,379 |
Regulatory Liabilities - Long -Term | 228,163 | 232,893 |
Other | 2,563 | 3,329 |
Total Deferred Credits | 355,784 | 358,102 |
Capitalization | ||
Long-Term Debt—Net | 589,960 | 490,380 |
Common Shares, Par Value $5 Per Share—Authorized, 50,000,000 Shares; Outstanding, 2018—39,651,436 Shares; 2017—39,557,491 Shares | 198,257 | 197,787 |
Premium on Common Shares | 342,690 | 343,450 |
Retained Earnings | 179,605 | 161,286 |
Accumulated Other Comprehensive Loss | (5,971) | (5,631) |
Total Common Equity | 714,581 | 696,892 |
Total Capitalization | 1,304,541 | 1,187,272 |
Total Liabilities and Equity | 2,011,247 | 2,004,278 |
Cumulative Preferred Shares [Member] | ||
Capitalization | ||
Cumulative Shares | ||
Cumulative Preference Shares [Member] | ||
Capitalization | ||
Cumulative Shares |
Consolidated Balance Sheets (C3
Consolidated Balance Sheets (Current Period Not Audited) (Parentheticals) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
Common shares, par value (in dollars per share) | $ 5 | $ 5 |
Common shares, authorized (in shares) | 50,000,000 | 50,000,000 |
Common shares, outstanding (in shares) | 39,651,436 | 39,557,491 |
Cumulative Preferred Shares [Member] | ||
Cumulative shares, authorized (in shares) | 1,500,000 | 1,500,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding (in shares) | 0 | 0 |
Cumulative Preference Shares [Member] | ||
Cumulative shares, authorized (in shares) | 1,000,000 | 1,000,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding (in shares) | 0 | 0 |
Consolidated Statements of Inco
Consolidated Statements of Income (Not Audited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Operating Revenues: | ||||
Operating Revenues | $ 226,348 | $ 212,086 | $ 467,614 | $ 426,203 |
Operating Expenses | ||||
Production Fuel – Electric | 15,888 | 12,477 | 34,594 | 28,859 |
Cost of Products Sold (depreciation included below) | 93,545 | 84,013 | 182,330 | 159,290 |
Electric Operation and Maintenance Expenses | 37,741 | 36,748 | 77,216 | 74,025 |
Other Nonelectric Expenses | 12,649 | 9,859 | 25,143 | 19,994 |
Depreciation and Amortization | 18,745 | 17,908 | 37,508 | 35,762 |
Property Taxes – Electric | 3,273 | 3,709 | 7,108 | 7,507 |
Total Operating Expenses | 196,243 | 181,090 | 399,894 | 361,001 |
Operating Income | 30,105 | 30,996 | 67,720 | 65,202 |
Interest Charges | 7,676 | 7,527 | 15,048 | 14,989 |
Nonservice Cost Components of Postretirement Benefits | 1,386 | 1,407 | 2,803 | 2,812 |
Other Income | 707 | 552 | 1,890 | 1,105 |
Income Before Income Taxes – Continuing Operations | 21,750 | 22,614 | 51,759 | 48,506 |
Income Tax Expense – Continuing Operations | 3,054 | 5,897 | 6,848 | 12,260 |
Net Income from Continuing Operations | 18,696 | 16,717 | 44,911 | 36,246 |
Discontinued Operations | ||||
Income – net of Income Tax Expense of $0, $40, $0 and $78 for the respective periods | 61 | 117 | ||
Net Income | $ 18,696 | $ 16,778 | $ 44,911 | $ 36,363 |
Average Number of Common Shares Outstanding – Basic (in shares) | 39,605,717 | 39,462,865 | 39,578,296 | 39,406,834 |
Average Number of Common Shares Outstanding – Diluted (in shares) | 39,879,069 | 39,702,499 | 39,871,376 | 39,671,612 |
Basic Earnings Per Common Share: | ||||
Continuing Operations (in dollars per share) | $ 0.47 | $ 0.43 | $ 1.13 | $ 0.92 |
Discontinued Operations (in dollars per share) | ||||
(in dollars per share) | 0.47 | 0.43 | 1.13 | 0.92 |
Diluted Earnings Per Common Share: | ||||
Continuing Operations (in dollars per share) | 0.47 | 0.42 | 1.13 | 0.92 |
Discontinued Operations (in dollars per share) | ||||
(in dollars per share) | 0.47 | 0.42 | 1.13 | 0.92 |
Dividends Declared Per Common Share (in dollars per share) | $ 0.335 | $ 0.32 | $ 0.67 | $ 0.64 |
Electricity [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | $ 105,284 | $ 102,655 | $ 229,109 | $ 222,437 |
Changes in Accrued Revenues under Alternative Revenue Programs | (1,565) | (424) | (2,440) | (1,663) |
Operating Revenues | 103,719 | 102,231 | 226,669 | 220,774 |
Product [Member] | ||||
Operating Revenues: | ||||
Revenues from Contracts with Customers | 122,629 | 109,855 | 240,945 | 205,429 |
Electricity, Purchased [Member] | ||||
Operating Expenses | ||||
Cost of Products Sold (depreciation included below) | $ 14,402 | $ 16,376 | $ 35,995 | $ 35,564 |
Consolidated Statements of Inc5
Consolidated Statements of Income (Not Audited) (Parentheticals) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income Tax Expense - Discontinued Operations | $ 0 | $ 40 | $ 0 | $ 78 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Not Audited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Net Income | $ 18,696 | $ 16,778 | $ 44,911 | $ 36,363 |
Unrealized (Loss) Gain on Available-for-Sale Securities: | ||||
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period | (1) | (110) | (1) | |
Unrealized (Losses) Gains Arising During Period | (13) | 21 | (79) | 38 |
Income Tax Benefit (Expense) | 3 | (7) | 40 | (13) |
Change in Unrealized Gains on Available-for-Sale Securities – net-of-tax | (10) | 13 | (149) | 24 |
Pension and Postretirement Benefit Plans: | ||||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 10) | 233 | 159 | 460 | 316 |
Income Tax Expense | (61) | (63) | (120) | (126) |
Adjustment to Income Tax Expense Related to 2017 Tax Cuts and Jobs Act | (531) | |||
Pension and Postretirement Benefit Plans – net-of-tax | 172 | 96 | (191) | 190 |
Total Other Comprehensive Income (Loss) | 162 | 109 | (340) | 214 |
Total Comprehensive Income | $ 18,858 | $ 16,887 | $ 44,571 | $ 36,577 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Not Audited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash Flows from Operating Activities | ||
Net Income | $ 44,911 | $ 36,363 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Net Income from Discontinued Operations | (117) | |
Depreciation and Amortization | 37,508 | 35,762 |
Deferred Tax Credits | (703) | (734) |
Deferred Income Taxes | 2,076 | 8,666 |
Change in Deferred Debits and Other Assets | 10,309 | 8,075 |
Discretionary Contribution to Pension Plan | (20,000) | |
Change in Noncurrent Liabilities and Deferred Credits | (759) | (695) |
Allowance for Equity/Other Funds Used During Construction | (1,060) | (401) |
Stock Compensation Expense—Equity Awards | 2,253 | 1,920 |
Other—Net | (193) | 39 |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (25,677) | (12,832) |
Change in Inventories | (2,401) | (3,527) |
Change in Other Current Assets | 2,428 | 2,095 |
Change in Payables and Other Current Liabilities | 1,433 | (5,878) |
Change in Interest and Income Taxes Receivable/Payable | 3,470 | 590 |
Net Cash Provided by Continuing Operations | 53,595 | 69,326 |
Net Cash Used in Discontinued Operations | (200) | (54) |
Net Cash Provided by Operating Activities | 53,395 | 69,272 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (49,094) | (56,354) |
Net Proceeds from Disposal of Noncurrent Assets | 1,477 | 2,167 |
Cash Used for Investments and Other Assets | (2,102) | (2,431) |
Net Cash Used in Investing Activities | (49,719) | (56,618) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | 2,236 | 1,043 |
Net Short-Term (Repayments) Borrowings | (91,394) | 15,234 |
Proceeds from Issuance of Common Stock | 4,266 | |
Common Stock Issuance Expenses | (108) | |
Payments for Retirement of Capital Stock | (2,450) | (1,799) |
Proceeds from Issuance of Long-Term Debt | 100,000 | |
Short-Term and Long-Term Debt Issuance Expenses | (441) | |
Payments for Retirement of Long-Term Debt | (107) | (6,114) |
Dividends Paid | (26,592) | (25,284) |
Net Cash Used in Financing Activities | (18,856) | (12,654) |
Net Change in Cash and Cash Equivalents | (15,180) | |
Cash and Cash Equivalents at Beginning of Period | 16,216 | |
Cash and Cash Equivalents at End of Period | $ 1,036 |
Note 1 - Summary of Significant
Note 1 - Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Significant Accounting Policies and New Accounting Pronouncements [Text Block] | 1. Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP 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 (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three six June 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three six June 30, 2018 2017. Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company third may Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 June 30, 2018 $55.7 35% Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: June 30, December 31, (in thousands) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first six 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312 New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01 December 15, 2017, 2016 01 first 2018, ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three six June 30, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $0.8 |
Note 2 - Segment Information
Note 2 - Segment Information | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Segment Reporting Disclosure [Text Block] | 2. Segment Information Segment Information The accounting policies of the segments are described under note 1 three three Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing PVC pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not No 10% 2017. one 11.7% 2017 one 24.3% 2017 one 12.0% 2017 two 20.6% 17.8% 2017 one All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 98.2% 98.3% three June 30, 2018 2017, 98.3% 98.3% six June 30, 2018 2017. The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for the three six June 30, 2018 2017 June 30, 2018 December 31, 2017 Operating Revenue Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 89,400 $ 86,679 $ 198,580 $ 193,133 Changes in Accrued ARP Revenues (1,565 ) (424 ) (2,440 ) (1,663 ) Total Retail Sales Revenue 87,835 86,255 196,140 191,470 Wholesale Revenues – Company Generation 2,539 1,184 3,554 2,051 Other Revenues 13,351 14,797 26,996 27,266 Total Electric Segment Revenues $ 103,725 $ 102,236 $ 226,690 $ 220,787 Manufacturing Segment: Metal Parts and Tooling $ 57,388 $ 49,450 $ 114,315 $ 97,528 Plastic Products and Tooling 7,961 7,376 18,196 16,928 Other 2,805 2,478 4,305 3,265 Total Manufacturing Segment Revenues $ 68,154 $ 59,304 $ 136,816 $ 117,721 Plastics Segment – Sale of PVC Pipe Products $ 54,476 $ 50,551 $ 104,129 $ 87,708 Intersegment Eliminations $ (7 ) $ (5 ) $ (21 ) $ (13 ) Total $ 226,348 $ 212,086 $ 467,614 $ 426,203 Interest Charges Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,687 $ 6,439 $ 13,077 $ 12,825 Manufacturing 555 553 1,109 1,107 Plastics 160 173 310 326 Corporate and Intersegment Eliminations 274 362 552 731 Total $ 7,676 $ 7,527 $ 15,048 $ 14,989 Income Taxes Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 611 $ 2,442 $ 2,709 $ 8,504 Manufacturing 1,018 1,573 2,241 2,628 Plastics 2,207 2,858 4,621 4,248 Corporate (782 ) (976 ) (2,723 ) (3,120 ) Total $ 3,054 $ 5,897 $ 6,848 $ 12,260 Net Income (Loss) Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 10,600 $ 10,134 $ 27,268 $ 25,694 Manufacturing 3,583 2,955 7,747 5,127 Plastics 6,229 4,637 13,073 7,074 Corporate (1,716 ) (1,009 ) (3,177 ) (1,649 ) Discontinued Operations -- 61 -- 117 Total $ 18,696 $ 16,778 $ 44,911 $ 36,363 Identifiable Assets June 30, December 31, (in thousands) 2018 2017 Electric $ 1,687,799 $ 1,690,224 Manufacturing 181,094 167,023 Plastics 99,205 87,230 Corporate 43,149 59,801 Total $ 2,011,247 $ 2,004,278 |
Note 3 - Rate and Regulatory Ma
Note 3 - Rate and Regulatory Matters | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Public Utilities Disclosure [Text Block] | 3. Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2018 2017. Major Capital Expenditure Projects Big Stone South–Ellendale Multi-Value Transmission Project (MVP) 345 163 December 2011. second 2016 2019. June 30, 2018 $99.4 100% Big Stone South–Brookings MVP 345 70 December 2011. third 2015 September 8, 2017. June 30, 2018 $72.5 100% Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota General Rate s 2016 March 2017 May 1, 2017. 8.61% 7.5056% 10.74% 9.41%. The MPUC’s order also included: ( 1 2 OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 November 17, 2017. 1 2 9.41% 2016 April 16, 2016, October 31, 2017, $0.9 $1.4 12 November 1, 2017, Minnesota Conservation Improvement Programs (MNCIP) not May 25, 2016 13.5% 2017 12% 2018 10% 2019 1.7% 40% 2017 35% 2018 30% 2019 Based on results from the 2017 $2.6 2017. 2017 10% 2016 2017 not $2.6 March 30, 2018. June 13, 2018, May 30, 2018, $2.9 July 3, 2018 $2.6 July 13, 2018 $2.9 Transmission Cost Recovery Rider may In OTP’s 2016 May 1, 2017, two August 18, 2017 On June 11, 2018 July 11, 2018 June 30, 2018, $2.0 Environmental Cost Recovery Rider 2010 2016 November 2017. Renewable Resource Adjustment November 1, 2017, one 2017 2018. $1.3 $5.8 2018 November 1, 2018. North Dakota General Rates November 2, 2017 $13.1 8.72%. $13.1 7.97% 10.30%. December 20, 2017 $12.8 January 1, 2018. February 27, 2018 $4.5 $8.3 March 1, 2018. 2018 On March 23, 2018 $13.1 $7.1 4.8% $6.0 $4.8 $1.2 July 6, 2018. 9.77% 52.5% $5.4 March 2018 $7.1 4.8% 10.3%. no 2017 $1.8 June 30, 2018 third OTP’s previously approved general rate increase in North Dakota of $3.6 3.0%, November 25, 2009 December 2009. 8.62%, 10.75%. Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider South Dakota General Rate s April 20, 2018 $3.3 10.1%, first two October 18, 2018. second 1.7% OTP’s previously approved general rate increase in South Dakota of approximately $643,000 2.32% April 21, 2011 June 1, 2011. 8.50%. Transmission Cost Recovery Rider Environmental Cost Recovery Rider Reagent Costs and Emission Allowances Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2016 Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2017 Incentive and Cost Recovery R – March 30, 2018 October 1, 2018 $ 10,300 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2018 Annual Update R – July 3, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2018 Annual Update R – June 14, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 1 Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket. 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: Revenues R ecorded under R ider R ates Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,368 $ 2,102 $ 4,884 $ 4,068 Transmission Cost Recovery (458 ) 1,273 (487 ) 3,443 Environmental Cost Recovery (18 ) 2,812 (49 ) 5,636 Renewable Resource Recovery 659 -- 1,184 -- North Dakota Renewable Resource Adjustment 2,079 1,839 4,046 3,609 Transmission Cost Recovery 1,165 1,384 3,227 3,895 Environmental Cost Recovery 1,830 2,388 3,651 4,876 South Dakota Transmission Cost Recovery 250 287 786 728 Environmental Cost Recovery 515 545 1,035 1,142 Conservation Improvement Program Costs and Incentives 122 176 351 416 Total $ 8,512 $ 12,806 $ 18,628 $ 27,813 1 Includes MNCIP costs recovered in base rates. TCJA The TCJA reduced the federal corporate income tax rate from 35% 21%. 35% February 15, 2018 not February 1, 2018 December 31, 2017 June 30, 2018, $4.1 $0.8 January February 2018, $0.7 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 one MVPs—On December 16, 2010 On November 12, 2013 may 12.38% 9.15%. 15 November 12, 2013 February 11, 2015. December 22, 2015 10.32%, September 28, 2016 10.32%. September 2016 On November 6, 2014 50 January 5, 2015 November 12, 2013 10.82% 10.32% 0.5% September 28, 2016. On February 12, 2015 may 12.38% 8.67%. second second 15 February 12, 2015 May 11, 2016. June 18, 2015 February 16, 2016. June 30, 2016 9.7%. second Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 December 31, 2016, first 15 February June 2017 2016 $2.7 December 31, 2016 $1.6 June 30, 2018. In June 2014, two two April 2017 June 2014 not June 2014 April 2017 September 29, 2017 second second first |
Note 4 - Regulatory Assets and
Note 4 - Regulatory Assets and Liabilities | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Schedule of Regulatory Assets and Liabilities [Text Block] | 4. As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations 980 980 605 25 June 30, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 107,946 $ 117,036 see below Conservation Improvement Program Costs and Incentives 2 3,927 4,163 8,090 27 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,907 6,907 asset lives Deferred Marked-to-Market Losses 1 2,862 1,574 4,436 30 Big Stone II Unrecovered Project Costs – Minnesota 1 665 1,296 1,961 34 Debt Reacquisition Premiums 1 231 856 1,087 171 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 513 -- 513 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 392 492 59 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 422 422 asset lives North Dakota Deferred Rate Case Expenses Subject to Recovery 1 303 -- 303 12 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 223 -- 223 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 75 75 18 Total Regulatory Assets $ 17,914 $ 123,631 $ 141,545 Regulatory Liabilities: Deferred Income Taxes $ -- $ 147,858 $ 147,858 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 79,835 79,835 asset lives Refundable Fuel Clause Adjustment Revenues 4,972 -- 4,972 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 716 -- 716 4 North Dakota Renewable Resource Recovery Rider Accrued Refund 394 -- 394 9 North Dakota Transmission Cost Recovery Rider Accrued Refund 319 -- 319 12 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker -- 316 316 see below South Dakota Environmental Cost Recovery Rider Accrued Refund 308 -- 308 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 240 -- 240 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 231 -- 231 12 Other 6 81 87 186 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 61 24 85 18 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 49 49 see below Minnesota Renewable Resource Recovery Rider Accrued Refund 1 -- 1 4 Total Regulatory Liabilities $ 7,248 $ 228,163 $ 235,411 Net Regulatory Asset/(Liability) Position $ 10,666 $ (104,532 ) $ (93,866 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 ) 1 Costs subject to recovery excluding a rate of return. 2 Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. All Deferred Marked-to-Market Losses recorded as of June 30, 2018 December 2020. Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 171 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. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The 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. North Dakota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s current rate case in North Dakota and are currently being recovered beginning with the establishment of interim rates in January 2018. Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to amounts recoverable for investments in qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that have not June 30, 2018. MISO Schedule 26/26A 26/26A North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that had not December 31, 2017. Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 24 April 2016. North Dakota Environmental Cost Recovery Rider Accrued Revenues relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that had not December 31, 2017. The regulatory liability related to Deferred Income Taxes results from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of June 30, 2018. The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of June 30, 2018. 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, 2018. The Minnesota Southwest Power Pool Transmission Cost Tracker Refund relates to revenues billed for recovery of these transmission costs in excess of actual costs incurred that are subject to refund. 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, 2018. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects and for reagent and emission allowances costs that are recoverable from North Dakota customers as of June 30, 2018. The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of June 30, 2018. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which were subject to refund over a 24 April 2016. The Minnesota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of June 30, 2018. The Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that were refundable to Minnesota customers as of December 31, 2017. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 no 980 |
Note 5 - Reconciliation of Comm
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Stockholders Equity and Earnings per Share [Text Block] | 5 . Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share Reconciliation of Common Shareholders’ Equity (in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 767 (860 ) (93 ) Common Stock Retirements (297 ) (2,153 ) (2,450 ) Net Income 44,911 44,911 Other Comprehensive Loss (340 ) (340 ) Employee Stock Incentive Plans Expense 2,253 2,253 Common Dividends ($0.67 per share) (26,592 ) (26,592 ) Balance, June 30, 2018 $ 198,257 $ 342,690 $ 179,605 $ (5,971 ) $ 714,581 Shelf Registration s and Common Share Distribution Agreement On May 3, 2018 may May 3, 2021. May 3, 2018, 1,500,000 May 3, 2021. May 11, 2018. May 1, 2018 may Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2017 June 30, 2018: Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 19,950 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (59,431 ) Common Shares Outstanding, June 30, 2018 39,651,436 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, 2018 2017. not Three Months ended June 30 Six Months ended June 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,605,717 39,462,865 39,578,296 39,406,834 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 202,643 173,974 212,902 187,806 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,616 50,087 58,373 53,980 Nonvested Restricted Shares 10,733 12,719 19,188 19,894 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,360 2,854 2,617 3,098 Total Dilutive Shares 273,352 239,634 293,080 264,778 Weighted Average Common Shares Outstanding – Diluted 39,879,069 39,702,499 39,871,376 39,671,612 The effect of dilutive shares on earnings per share for the three six June 30, 2018 2017, no $ 0.01 |
Note 6 - Share-based Payments
Note 6 - Share-based Payments | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | 6 . Share-Based Payments Stock Incentive Awards The following stock incentive awards were granted under the 2014 six June 30, 2018: Award Grant-Date Shares/Units Granted Weighted Average Grant-Date Fair Value per Award Vesting Stock Performance Awards Granted to Executive Officers February 5, 2018 54,000 $ 35.73 December 31, 2020 Restricted Stock Units Granted to Executive Officers February 5, 2018 15,200 $ 41.325 25% per year through February 6, 2022 Restricted Stock Units Granted to Key Employees April 9, 2018 12,945 $ 38.45 100% on April 8, 2022 Restricted Stock Units Granted to Key Employee June 20, 2018 1,000 $ 42.46 100% on April 8, 2022 Restricted Stock Granted to Nonemployee Directors April 9, 2018 18,200 $ 43.40 33% per year through April 8, 2021 Under the performance share awards the aggregate award for performance at target is 54,000 27,000 3 27,000 January 1, 2018 December 31, 2020, 20 January 1, 2018 20 January 1, 2021. may zero 150% 81,000 no 718, The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards’ respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit granted to an executive officer was the average of the high and low market price of one not one The restricted shares granted to the Company’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not one The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of June 30, 2018, $6.2 2.2 Amounts of compensation expense recognized under the Company’s five three six June 30, 2018 2017 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 668 $ 425 $ 1,319 $ 1,074 Restricted Stock Units Granted to Executive Officers 173 104 422 368 Restricted Stock Granted to Executive Officers -- 16 16 38 Restricted Stock Granted to Nonemployee Directors 165 144 331 272 Restricted Stock Units Granted to Key Employees 101 81 165 168 Totals $ 1,107 $ 770 $ 2,253 $ 1,920 |
Note 7 - Retained Earnings and
Note 7 - Retained Earnings and Dividend Restriction | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Retained Earnings Restrictions [Text Block] | 7 . Retained Earnings and Dividend Restriction The Company is a holding company with no Both the Company and OTP credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not June 30, 2018, Under the Federal Power Act, a public utility may not 1 2 not 3 no The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.4% 58.0% 2017 September 1, 2017. June 30, 2018, 52.5% $473,000,000. $1,178,024,000. On May 1, 2018 47.9% 58.5% 2018 not $1,204,416,000. June 15, 2018 |
Note 8 - Commitments and Contin
Note 8 - Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | 8 . Commitments and Contingencies Construction and Other Purchase Commitments At June 30, 2018 2019 $45.3 December 31, 2017 2019 $41.0 June 30, 2018 December 31, 2021 $5.8 December 31, 2017 December 31, 2021 $6.7 Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2041. 2040. 2020. May 14, 2018 December 31, 2020. no 2018 2019 December 31, 2023. no Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. In the first 2018, May 2018 June 2021, $216,000 2018, $324,000 2019, $324,000 2020 $162,000 2021. June 2018 63 July 2018 September 2023, $79,000 2018, $322,000 2019, $332,000 2020, $342,000 2021, $352,000 2022 $271,000 2023. Contingencies OTP had a $1.6 June 30, 2018 Together with as many as 200 April 1, 2005 May 2, 2015. not June 28, 2018 not July 30, 2018. No Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. In addition to the ROE refund described earlier, the most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with warranty claims relating to divested businesses that could exceed the established reserve amounts and litigation matters. Should all of these known items, excluding the ROE refund liability already recognized, result in liabilities being incurred, the loss could be as high as $1.0 In 2014 CO2 CO2 111 October 23, 2015. February 9, 2016 September 27, 2016 first 2017. 13783, CO2 October 16, 2017 Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of June 30, 2018 not |
Note 9 - Short-term and Long-te
Note 9 - Short-term and Long-term Borrowings | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Debt Disclosure [Text Block] | 9 . Short-Term and Long-Term Borrowings The following table presents the status of the Company’s lines of credit as of June 30, 2018 December 31, 2017: (in thousands) Line Limit In Use on June 30, 2018 Restricted due to Outstanding Letters of Credit Available on June 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,102 $ -- $ 123,898 $ 130,000 OTP Credit Agreement 170,000 14,875 300 154,825 57,329 Total $ 300,000 $ 20,977 $ 300 $ 278,723 $ 187,329 Debt Issuances 2018 On November 14, 2017, 2018 $100 4.07% 2018A February 7, 2048 ( 2018 2018 February 7, 2018. 2018 OTP may not 10% 100% no August 7, 2047 2018 100% 2018 The 2018 2018 2018 not 2018 not 2018 2018 2018 2018 2018 2018 no The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 14,875 $ 6,102 $ 20,977 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, fully repaid April 1, 2018 -- -- PACE Note, 2.54%, due March 18, 2021 604 604 Total $ 512,000 $ 80,604 $ 592,604 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 167 167 Unamortized Long-Term Debt Issuance Costs 2,045 432 2,477 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,955 $ 80,005 $ 589,960 Total Short-Term and Long-Term Debt (with current maturities) $ 524,830 $ 86,274 $ 611,104 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937 |
Note 10 - Pension Plan and Othe
Note 10 - Pension Plan and Other Postretirement Benefits | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | 1 0 . Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 3,230 $ 2,814 Interest Cost on Projected Benefit Obligation 3,363 3,536 6,726 7,070 Expected Return on Assets (5,299 ) (4,807 ) (10,599 ) (9,614 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 29 8 59 From Other Comprehensive Income 1 -- 1 -- 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,783 1,272 3,567 2,545 From Other Comprehensive Income 1 47 32 91 63 Net Periodic Pension Cost 2 $ 1,513 $ 1,470 $ 3,023 $ 2,939 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (77 ) 50 (161 ) 100 Cash flows no December 31, 2017 $20 first 2018. Executive Survivor and Supplemental Retirement Plan Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 72 $ 200 $ 145 Interest Cost on Projected Benefit Obligation 399 421 798 843 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 9 10 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 67 72 134 143 From Other Comprehensive Income 1 165 110 330 220 Net Periodic Pension Cost 2 $ 744 $ 689 $ 1,489 $ 1,378 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in n onservice cost components of postretirement benefits 644 617 1,289 1,233 Postretirement Benefits Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 381 $ 356 $ 763 $ 712 Interest Cost on Projected Benefit Obligation 646 678 1,291 1,356 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 824 466 From Other Comprehensive Income 1 11 6 21 12 Net Periodic Postretirement Benefit Cost 2 $ 1,450 $ 1,273 $ 2,899 $ 2,546 Effect of Medicare Part D Subsidy $ (36 ) $ (140 ) $ (73 ) $ (280 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in n onservice cost components of postretirement benefits 818 738 1,668 1,477 |
Note 11 - Fair Value of Financi
Note 11 - Fair Value of Financial Instruments | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Fair Value Disclosures [Text Block] | 1 1 . Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Cash Equivalents Short-Term Debt June 30, 2018 December 31, 2017 LIBOR 1.50% LIBOR 1.25% Long-Term Debt including Current Maturities 2 820. June 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,036 $ 1,036 $ 16,216 $ 16,216 Short-Term Debt (20,977 ) (20,977 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,127 ) (605,185 ) (490,566 ) (543,691 ) |
Note 13 - Income Tax Expense -
Note 13 - Income Tax Expense - Continuing Operations | 6 Months Ended |
Jun. 30, 2018 | |
Notes to Financial Statements | |
Income Tax Disclosure [Text Block] | 1 3 . Income Tax Expense – Continuing Operations The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income: Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 21,750 $ 22,614 $ 51,759 $ 48,506 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 5,655 $ 8,819 $ 13,457 $ 18,917 Increases (Decreases) in Tax from: Property Related Differences and Other Regulatory Adjustments (1,025 ) 35 (2,098 ) 140 Federal Production Tax Credits (930 ) (2,010 ) (2,050 ) (4,062 ) Excess Tax Deduction – Equity Method Stock Awards -- -- (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (213 ) (516 ) (425 ) Research and Development and Other Tax Credits (202 ) (190 ) (409 ) (387 ) Allowance for Funds Used During Construction – Equity (111 ) (91 ) (278 ) (158 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (199 ) (345 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (660 ) Other Items – Net 24 49 96 (63 ) Income Tax Expense – Continuing Operations $ 3,054 $ 5,897 $ 6,848 $ 12,260 Effective Income Tax Rate – Continuing Operations 14.0 % 26.1 % 13.2 % 25.3 % The following table summarizes the activity related to the Company’s unrecognized tax benefits: (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 72 147 Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 712 $ 1,038 The balance of unrecognized tax benefits as of June 30, 2018 June 30, 2018 not 12 no June 30, 2018. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of August 1, 2018, no 2014 The Company recognized the income tax effects of the TCJA in its 2017 No. 118, 740, Income Taxes one December 31, 2017 may may June 30, 2018 not December 31, 2017. |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition In May 2014 No. 2014 09, Revenue from Contracts with Customers (Topic 606 606 606 January 1, 2018 not 606 no 606 606 Due to the diverse business operations of the Company, recognition of revenue from contracts with customers depends on the product produced and sold or service performed. The Company recognizes revenue from contracts with customers, at prices that are fixed or determinable as evidenced by an agreement with the customer, when the Company has met its performance obligation under the contract and it is probable that the Company will collect the amount to which it is entitled in exchange for the goods or services transferred or to be transferred to the customer. Depending on the product produced and sold or service performed and the terms of the agreement with the customer, the Company recognizes revenue either over time, in the case of delivery or transmission of electricity or related services or the production and storage of certain custom-made products, or at a point in time for the delivery of standardized products and other products made to the customers specifications where the terms of the contract require transfer of the completed product. Based on review of the Company’s revenue streams, the Company has not 606. In addition to recognizing revenue from contracts with customers under ASC 606, 980, Regulated Operations 980 not Electric Segment Revenues two 1 2 Most Electric segment revenues are earned from the generation, transmission and sale of electricity to retail customers at rates approved by regulatory commissions in the states where Otter Tail Power Company (OTP) provides service. OTP also earns revenue from the transmission of electricity for others over the transmission assets it owns separately or jointly with other transmission service providers under rate tariffs established by the independent transmission system operator and approved by the Federal Energy Regulatory Commission (FERC). A third ARPs provide for adjustments to rates outside of a general rate case proceeding, usually as a surcharge applied to future billings typically through the use of rate riders subject to periodic adjustments, to encourage or incentivize investments in certain areas such as conservation, renewable energy, pollution reduction or control, improved infrastructure of the transmission grid or other programs that provide benefits to the general public under public policy, laws or regulations. ARP riders generally provide for the recovery of specified costs and investments and include an incentive component to provide the regulated utility with a return on amounts invested. OTP 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 (CIP) riders. ● In North Dakota: TCR, ECR and RRA riders ● In South Dakota: TCR, ECR and Energy Efficiency Plan (conservation) riders. OTP accrues ARP revenue on the basis of costs incurred, investments made and returns on those investments that qualify for recovery through established riders. Amounts billed under riders in effect at the time of the billing are included in revenues from contracts with customers 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 ARP revenue adjustments on a separate line in the revenue section of the Company’s consolidated statement of income. See table in note 3 three six June 30, 2018 2017. Manufacturing Segment Revenues no Plastics Segment Revenues no one See operating revenue table in note 2 three six June 30, 2018 2017. |
Agreements Subject to Legally Enforceable Netting Arrangements [Policy Text Block] | Agreements Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The Company does not |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value Measurements The Company follows ASC Topic 820, Fair Value Measurements and Disclosures 820 820 three Level 1 1 Level 2 2 Level 3 no 3 may The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 The valuation techniques and inputs used for the Level 2 Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company third may |
Consolidation, Variable Interest Entity, Policy [Policy Text Block] | Coyote Station Lignite Supply Agreement – Variable Interest Entity In October 2012 May 2016 December 2040. May 2016 December 2040 No none, none not If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 June 30, 2018 $55.7 35% |
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) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034 |
Goodwill and Intangible Assets, Policy [Policy Text Block] | Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2017 not The following table indicates there were no first six 2018: (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360 10 35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at June 30, 2018 December 31, 2017: June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 The amortization expense for these intangible assets was: Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665 The estimated annual amortization expense for these intangible assets for the next five (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 |
Cash Flow Supplemental [Policy Text Block] | Supplemental Disclosures of Cash Flow Information As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312 |
New Accounting Pronouncements, Policy [Policy Text Block] | New Accounting Standards Adopted ASU 2014 09 May 2014 2014 09, Revenue from Contracts with Customers (Topic 606 606 January 1, 2018 ASU 2016 01 January 2016 No. 2016 01, Financial Instruments—Overall (Subtopic 825 10 2016 01 2016 01 2016 01 December 15, 2017, 2016 01 first 2018, ASU 2017 07 March 2017 No. 2017 07, Compensation—Retirement Benefits (Topic 715 2017 07 715, Compensation—Retirement Benefits 715 , not not 2017 07 715 2017 07 2017 07 December 15, 2017, The majority of the Company’s benefit costs to which the amendments in ASU 2017 07 2017 07 2017 07 2017 07. The Company’s non-service cost components of net periodic post-retirement benefit costs that were capitalized to plant in service in 2017 2017 07 2017 $0.8 2017 2016 2018 10 2017 07 $5.6 2017 $5.1 2016. three six June 30, 2018 2017 10 New Accounting Standards Pending Adoption ASU 2016 02 February 2016 No. 2016 02, Leases (Topic 842 2016 02 2016 02 842, 840 842 842 842 842 2016 02 December 15, 2018, 2016 02 2016 02, 2016 02 not 2016 02 2019. ASU 2017 04 January 2017 No. 2017 04, Intangibles—Goodwill and Other (Topic 350 2017 04 2 2 2, 2017 04, not The amendments in ASU 2017 04 no 2 2017 04 December 15, 2019. January 1, 2017. ASU 2018 02 February 2018 No. 2018 02, Income Statement—Reporting Comprehensive Income (Topic 220 ): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income 2018 02 2018 02, 2017 2018 02 December 15, 2018, 2018 02 2018 02 not 2018 02 first 2019. $0.8 |
Note 1 - Summary of Significa21
Note 1 - Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | June 30 , 2018 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,233 Corporate Debt Securities – Held by Captive Insurance Company $ 5,630 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,527 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 945 Total Assets $ 2,178 $ 7,157 December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Equity Funds – Held by Captive Insurance Company $ 1,285 Corporate Debt Securities – Held by Captive Insurance Company $ 5,373 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 1,787 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan 823 Total Assets $ 2,108 $ 7,160 |
Schedule of Inventory, Current [Table Text Block] | June 30, December 31, (in thousands) 2018 2017 Finished Goods $ 27,140 $ 26,605 Work in Process 17,000 14,222 Raw Material, Fuel and Supplies 46,295 47,207 Total Inventories $ 90,435 $ 88,034 |
Schedule of Goodwill [Table Text Block] | (in thousands) Gross Balance December 31, 2017 Accumulated Impairments Balance (net of impairments) December 31, 2017 Adjustments to Goodwill in 2018 Balance (net of impairments) June 30, 2018 Manufacturing $ 18,270 $ -- $ 18,270 $ -- $ 18,270 Plastics 19,302 -- 19,302 -- 19,302 Total $ 37,572 $ -- $ 37,572 $ -- $ 37,572 |
Schedule of Other Intangible Assets [Table Text Block] | June 30 , 2018 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 9,560 $ 12,931 18 - 206 Covenant not to Compete 590 557 33 2 Other 154 43 111 26 Total $ 23,235 $ 10,160 $ 13,075 December 31, 2017 (in thousands) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Remaining Amortization Periods (months) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,994 $ 13,497 24 - 212 Covenant not to Compete 590 459 131 8 Other 154 17 137 32 Total $ 23,235 $ 9,470 $ 13,765 |
Finite-lived Intangible Assets Amortization Expense [Table Text Block] | Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Amortization Expense – Intangible Assets $ 345 $ 333 $ 690 $ 665 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block] | (in thousands) 2018 2019 2020 2021 2022 Estimated Amortization Expense – Intangible Assets $ 1,315 $ 1,184 $ 1,133 $ 1,099 $ 1,099 |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | As of June 30, (in thousands) 2018 2017 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 11,564 $ 16,312 |
Note 2 - Segment Information (T
Note 2 - Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Segment Reporting Information, by Segment [Table Text Block] | Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric Segment: Retail Sales Revenue from Contracts with Customers $ 89,400 $ 86,679 $ 198,580 $ 193,133 Changes in Accrued ARP Revenues (1,565 ) (424 ) (2,440 ) (1,663 ) Total Retail Sales Revenue 87,835 86,255 196,140 191,470 Wholesale Revenues – Company Generation 2,539 1,184 3,554 2,051 Other Revenues 13,351 14,797 26,996 27,266 Total Electric Segment Revenues $ 103,725 $ 102,236 $ 226,690 $ 220,787 Manufacturing Segment: Metal Parts and Tooling $ 57,388 $ 49,450 $ 114,315 $ 97,528 Plastic Products and Tooling 7,961 7,376 18,196 16,928 Other 2,805 2,478 4,305 3,265 Total Manufacturing Segment Revenues $ 68,154 $ 59,304 $ 136,816 $ 117,721 Plastics Segment – Sale of PVC Pipe Products $ 54,476 $ 50,551 $ 104,129 $ 87,708 Intersegment Eliminations $ (7 ) $ (5 ) $ (21 ) $ (13 ) Total $ 226,348 $ 212,086 $ 467,614 $ 426,203 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 6,687 $ 6,439 $ 13,077 $ 12,825 Manufacturing 555 553 1,109 1,107 Plastics 160 173 310 326 Corporate and Intersegment Eliminations 274 362 552 731 Total $ 7,676 $ 7,527 $ 15,048 $ 14,989 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 611 $ 2,442 $ 2,709 $ 8,504 Manufacturing 1,018 1,573 2,241 2,628 Plastics 2,207 2,858 4,621 4,248 Corporate (782 ) (976 ) (2,723 ) (3,120 ) Total $ 3,054 $ 5,897 $ 6,848 $ 12,260 Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2018 2017 2018 2017 Electric $ 10,600 $ 10,134 $ 27,268 $ 25,694 Manufacturing 3,583 2,955 7,747 5,127 Plastics 6,229 4,637 13,073 7,074 Corporate (1,716 ) (1,009 ) (3,177 ) (1,649 ) Discontinued Operations -- 61 -- 117 Total $ 18,696 $ 16,778 $ 44,911 $ 36,363 June 30, December 31, (in thousands) 2018 2017 Electric $ 1,687,799 $ 1,690,224 Manufacturing 181,094 167,023 Plastics 99,205 87,230 Corporate 43,149 59,801 Total $ 2,011,247 $ 2,004,278 |
Note 3 - Rate and Regulatory 23
Note 3 - Rate and Regulatory Matters (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Information on Status of Updates for Previous Periods [Table Text Block] | Rate Rider R - Request Date A - Approval Date Effective Date Requested or Approved Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2017 Incentive and Cost Recovery R – March 30, 2018 October 1, 2018 $ 10,300 $0.00600/kwh 2016 Incentive and Cost Recovery A – September 15, 2017 October 1, 2017 $ 9,868 $0.00536/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh Transmission Cost Recovery 2017 Rate Reset 1 A – October 30, 2017 November 1, 2017 $ (3,311 ) Various 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various Environmental Cost Recovery 2018 Annual Update R – July 3, 2018 December 1, 2018 $ -- 0% of base 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ (1,943 ) -0.935% of base 2016 Annual Update A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of base Renewable Resource Adjustment 2018 Annual Update R – June 14, 2018 November 1, 2018 $ 5,886 $.00244/kwh 2017 Rate Reset A – October 30, 2017 November 1, 2017 $ 1,279 $.00049/kwh North Dakota Renewable Resource Adjustment 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 9,650 7.493% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 9,989 7.756% of base 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of base 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of base Transmission Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,469 Various 2017 Annual Update A – November 29, 2017 January 1, 2018 $ 7,959 Various 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various Environmental Cost Recovery 2018 Rate Reset for effect of TCJA A – February 27, 2018 March 1, 2018 $ 7,718 5.593% of base 2017 Rate Reset A – December 20, 2017 January 1, 2018 $ 8,537 6.629% of base 2017 Annual Update A – July 12, 2017 August 1, 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base South Dakota Transmission Cost Recovery 2017 Annual Update A – February 28, 2018 March 1, 2018 $ 1,779 Various 2016 Annual Update A – February 17, 2017 March 1, 2017 $ 2,053 Various 2015 Annual Update A – February 12, 2016 March 1, 2016 $ 1,895 Various Environmental Cost Recovery 2017 Annual Update A – October 13, 2017 November 1, 2017 $ 2,082 $0.00483/kwh 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh |
Schedule of Revenues Recorded under Rate Riders [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, Rate Rider (in thousands) 2018 2017 2018 2017 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 2,368 $ 2,102 $ 4,884 $ 4,068 Transmission Cost Recovery (458 ) 1,273 (487 ) 3,443 Environmental Cost Recovery (18 ) 2,812 (49 ) 5,636 Renewable Resource Recovery 659 -- 1,184 -- North Dakota Renewable Resource Adjustment 2,079 1,839 4,046 3,609 Transmission Cost Recovery 1,165 1,384 3,227 3,895 Environmental Cost Recovery 1,830 2,388 3,651 4,876 South Dakota Transmission Cost Recovery 250 287 786 728 Environmental Cost Recovery 515 545 1,035 1,142 Conservation Improvement Program Costs and Incentives 122 176 351 416 Total $ 8,512 $ 12,806 $ 18,628 $ 27,813 |
Note 4 - Regulatory Assets an24
Note 4 - Regulatory Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Regulatory Assets and Liabilities [Table Text Block] | June 30, 2018 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 107,946 $ 117,036 see below Conservation Improvement Program Costs and Incentives 2 3,927 4,163 8,090 27 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,907 6,907 asset lives Deferred Marked-to-Market Losses 1 2,862 1,574 4,436 30 Big Stone II Unrecovered Project Costs – Minnesota 1 665 1,296 1,961 34 Debt Reacquisition Premiums 1 231 856 1,087 171 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 513 -- 513 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 392 492 59 Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery 1 -- 422 422 asset lives North Dakota Deferred Rate Case Expenses Subject to Recovery 1 303 -- 303 12 Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 223 -- 223 18 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 75 75 18 Total Regulatory Assets $ 17,914 $ 123,631 $ 141,545 Regulatory Liabilities: Deferred Income Taxes $ -- $ 147,858 $ 147,858 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 79,835 79,835 asset lives Refundable Fuel Clause Adjustment Revenues 4,972 -- 4,972 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 716 -- 716 4 North Dakota Renewable Resource Recovery Rider Accrued Refund 394 -- 394 9 North Dakota Transmission Cost Recovery Rider Accrued Refund 319 -- 319 12 Minnesota Southwest Power Pool Transmission Cost Recovery Tracker -- 316 316 see below South Dakota Environmental Cost Recovery Rider Accrued Refund 308 -- 308 12 North Dakota Environmental Cost Recovery Rider Accrued Refund 240 -- 240 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 231 -- 231 12 Other 6 81 87 186 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 61 24 85 18 Revenue for Rate Case Expenses Subject to Refund – Minnesota -- 49 49 see below Minnesota Renewable Resource Recovery Rider Accrued Refund 1 -- 1 4 Total Regulatory Liabilities $ 7,248 $ 228,163 $ 235,411 Net Regulatory Asset/(Liability) Position $ 10,666 $ (104,532 ) $ (93,866 ) December 31, 2017 Remaining Recovery/ (in thousands) Current Long-Term Total Refund Period (months) Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 9,090 $ 112,487 $ 121,577 see below Conservation Improvement Program Costs and Incentives 2 7,385 2,774 10,159 21 Accumulated ARO Accretion/Depreciation Adjustment 1 -- 6,651 6,651 asset lives Deferred Marked-to-Market Losses 1 4,063 2,405 6,468 36 Big Stone II Unrecovered Project Costs – Minnesota 1 650 1,636 2,286 40 Debt Reacquisition Premiums 1 254 960 1,214 177 Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues 1 75 -- 75 12 Big Stone II Unrecovered Project Costs – South Dakota 1 100 442 542 65 North Dakota Deferred Rate Case Expenses Subject to Recovery 1 309 -- 309 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 1 -- 1,985 1,985 24 North Dakota Renewable Resource Rider Accrued Revenues 2 206 236 442 15 Minnesota Deferred Rate Case Expenses Subject to Recovery 1 267 -- 267 4 North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 152 -- 152 12 Total Regulatory Assets $ 22,551 $ 129,576 $ 152,127 Regulatory Liabilities: Deferred Income Taxes $ -- $ 149,052 $ 149,052 asset lives Accumulated Reserve for Estimated Removal Costs – Net of Salvage -- 83,100 83,100 asset lives Refundable Fuel Clause Adjustment Revenues 5,778 -- 5,778 12 Minnesota Environmental Cost Recovery Rider Accrued Refund 1,667 -- 1,667 11 North Dakota Transmission Cost Recovery Rider Accrued Refund 349 -- 349 12 Minnesota Southwest Power Pool Transmission Cost Tracker Refund -- 609 609 22 South Dakota Environmental Cost Recovery Rider Accrued Refund 187 -- 187 12 South Dakota Transmission Cost Recovery Rider Accrued Refund 151 -- 151 12 MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 132 48 180 24 Other 5 84 89 192 Revenue for Rate Case Expenses Subject to Refund – Minnesota 208 -- 208 4 Minnesota Renewable Resource Recovery Rider Accrued Refund 409 -- 409 12 Minnesota Transmission Cost Recovery Rider Accrued Refund 802 -- 802 10 Total Regulatory Liabilities $ 9,688 $ 232,893 $ 242,581 Net Regulatory Asset/(Liability) Position $ 12,863 $ (103,317 ) $ (90,454 ) |
Note 5 - Reconciliation of Co25
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Stockholders Equity [Table Text Block] | (in thousands) Par Value, Common Shares Premium on Common Shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Equity Balance, December 31, 2017 $ 197,787 $ 343,450 $ 161,286 $ (5,631 ) $ 696,892 Common Stock Issuances, Net of Expenses 767 (860 ) (93 ) Common Stock Retirements (297 ) (2,153 ) (2,450 ) Net Income 44,911 44,911 Other Comprehensive Loss (340 ) (340 ) Employee Stock Incentive Plans Expense 2,253 2,253 Common Dividends ($0.67 per share) (26,592 ) (26,592 ) Balance, June 30, 2018 $ 198,257 $ 342,690 $ 179,605 $ (5,971 ) $ 714,581 |
Schedule of Common Stock Outstanding Roll Forward [Table Text Block] | Common Shares Outstanding, December 31, 2017 39,557,491 Issuances: Executive Stock Performance Awards (2015 shares earned) 114,648 Vesting of Restricted Stock Units 19,950 Restricted Stock Issued to Directors 18,200 Directors Deferred Compensation 578 Retirements: Shares Withheld for Individual Income Tax Requirements (59,431 ) Common Shares Outstanding, June 30, 2018 39,651,436 |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Three Months ended June 30 Six Months ended June 30 2018 2017 2018 2017 Weighted Average Common Shares Outstanding – Basic 39,605,717 39,462,865 39,578,296 39,406,834 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 202,643 173,974 212,902 187,806 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,616 50,087 58,373 53,980 Nonvested Restricted Shares 10,733 12,719 19,188 19,894 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 2,360 2,854 2,617 3,098 Total Dilutive Shares 273,352 239,634 293,080 264,778 Weighted Average Common Shares Outstanding – Diluted 39,879,069 39,702,499 39,871,376 39,671,612 |
Note 6 - Share-based Payments (
Note 6 - Share-based Payments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
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 to Executive Officers February 5, 2018 54,000 $ 35.73 December 31, 2020 Restricted Stock Units Granted to Executive Officers February 5, 2018 15,200 $ 41.325 25% per year through February 6, 2022 Restricted Stock Units Granted to Key Employees April 9, 2018 12,945 $ 38.45 100% on April 8, 2022 Restricted Stock Units Granted to Key Employee June 20, 2018 1,000 $ 42.46 100% on April 8, 2022 Restricted Stock Granted to Nonemployee Directors April 9, 2018 18,200 $ 43.40 33% per year through April 8, 2021 |
Share-based Compensation, Activity [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Stock Performance Awards Granted to Executive Officers $ 668 $ 425 $ 1,319 $ 1,074 Restricted Stock Units Granted to Executive Officers 173 104 422 368 Restricted Stock Granted to Executive Officers -- 16 16 38 Restricted Stock Granted to Nonemployee Directors 165 144 331 272 Restricted Stock Units Granted to Key Employees 101 81 165 168 Totals $ 1,107 $ 770 $ 2,253 $ 1,920 |
Note 9 - Short-term and Long-27
Note 9 - Short-term and Long-term Borrowings (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Line of Credit Facilities [Table Text Block] | (in thousands) Line Limit In Use on June 30, 2018 Restricted due to Outstanding Letters of Credit Available on June 30, 2018 Available on December 31, 2017 Otter Tail Corporation Credit Agreement $ 130,000 $ 6,102 $ -- $ 123,898 $ 130,000 OTP Credit Agreement 170,000 14,875 300 154,825 57,329 Total $ 300,000 $ 20,977 $ 300 $ 278,723 $ 187,329 |
Schedule of Debt [Table Text Block] | June 30 , 2018 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 14,875 $ 6,102 $ 20,977 Long-Term Debt: 3.55% Guaranteed Senior Notes, due December 15, 2026 $ 80,000 $ 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 Senior Unsecured Notes 4.07%, Series 2018A, due February 7, 2048 100,000 100,000 North Dakota Development Note, 3.95%, fully repaid April 1, 2018 -- -- PACE Note, 2.54%, due March 18, 2021 604 604 Total $ 512,000 $ 80,604 $ 592,604 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 167 167 Unamortized Long-Term Debt Issuance Costs 2,045 432 2,477 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 509,955 $ 80,005 $ 589,960 Total Short-Term and Long-Term Debt (with current maturities) $ 524,830 $ 86,274 $ 611,104 December 31, 2017 (in thousands) OTP Otter Tail Corporation Otter Tail Corporation Consolidated Short-Term Debt $ 112,371 $ -- $ 112,371 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ -- $ -- 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 4.63%, due December 1, 2021 $ 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 27 27 PACE Note, 2.54%, due March 18, 2021 684 684 Total $ 412,000 $ 80,711 $ 492,711 Less: Current Maturities net of Unamortized Debt Issuance Costs -- 186 186 Unamortized Long-Term Debt Issuance Costs 1,684 461 2,145 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,316 $ 80,064 $ 490,380 Total Short-Term and Long-Term Debt (with current maturities) $ 522,687 $ 80,250 $ 602,937 |
Note 10 - Pension Plan and Ot28
Note 10 - Pension Plan and Other Postretirement Benefits (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Net Benefit Costs [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 1,615 $ 1,407 $ 3,230 $ 2,814 Interest Cost on Projected Benefit Obligation 3,363 3,536 6,726 7,070 Expected Return on Assets (5,299 ) (4,807 ) (10,599 ) (9,614 ) Amortization of Prior-Service Cost: From Regulatory Asset 4 29 8 59 From Other Comprehensive Income 1 -- 1 -- 2 Amortization of Net Actuarial Loss: From Regulatory Asset 1,783 1,272 3,567 2,545 From Other Comprehensive Income 1 47 32 91 63 Net Periodic Pension Cost 2 $ 1,513 $ 1,470 $ 3,023 $ 2,939 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in n onservice cost components of postretirement benefits (77 ) 50 (161 ) 100 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 100 $ 72 $ 200 $ 145 Interest Cost on Projected Benefit Obligation 399 421 798 843 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 8 8 From Other Comprehensive Income 1 9 10 19 19 Amortization of Net Actuarial Loss: From Regulatory Asset 67 72 134 143 From Other Comprehensive Income 1 165 110 330 220 Net Periodic Pension Cost 2 $ 744 $ 689 $ 1,489 $ 1,378 1 Amortization of prior service costs and net actuarial losses from other comprehensive income are included in n onservice cost components of postretirement benefits on the face of the Company’s consolidated statements of income. 2 Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in n onservice cost components of postretirement benefits 644 617 1,289 1,233 Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Service Cost—Benefit Earned During the Period $ 381 $ 356 $ 763 $ 712 Interest Cost on Projected Benefit Obligation 646 678 1,291 1,356 Amortization of Net Actuarial Loss: From Regulatory Asset 412 233 824 466 From Other Comprehensive Income 1 11 6 21 12 Net Periodic Postretirement Benefit Cost 2 $ 1,450 $ 1,273 $ 2,899 $ 2,546 Effect of Medicare Part D Subsidy $ (36 ) $ (140 ) $ (73 ) $ (280 ) 1 Corporate cost included in nonservice cost components of postretirement benefits. 2 Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in n onservice cost components of postretirement benefits 818 738 1,668 1,477 |
Note 11 - Fair Value of Finan29
Note 11 - Fair Value of Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Fair Value, by Balance Sheet Grouping [Table Text Block] | June 30, 2018 December 31, 2017 (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value Cash and Cash Equivalents $ 1,036 $ 1,036 $ 16,216 $ 16,216 Short-Term Debt (20,977 ) (20,977 ) (112,371 ) (112,371 ) Long-Term Debt including Current Maturities (590,127 ) (605,185 ) (490,566 ) (543,691 ) |
Note 13 - Income Tax Expense 30
Note 13 - Income Tax Expense - Continuing Operations (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Notes Tables | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Income Before Income Taxes – Continuing Operations $ 21,750 $ 22,614 $ 51,759 $ 48,506 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) $ 5,655 $ 8,819 $ 13,457 $ 18,917 Increases (Decreases) in Tax from: Property Related Differences and Other Regulatory Adjustments (1,025 ) 35 (2,098 ) 140 Federal Production Tax Credits (930 ) (2,010 ) (2,050 ) (4,062 ) Excess Tax Deduction – Equity Method Stock Awards -- -- (624 ) (697 ) Other Comprehensive Income Deferred Tax Rate Adjustment -- -- (531 ) -- North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (258 ) (213 ) (516 ) (425 ) Research and Development and Other Tax Credits (202 ) (190 ) (409 ) (387 ) Allowance for Funds Used During Construction – Equity (111 ) (91 ) (278 ) (158 ) Employee Stock Ownership Plan Dividend Deduction (99 ) (172 ) (199 ) (345 ) Section 199 Domestic Production Activities Deduction -- (330 ) -- (660 ) Other Items – Net 24 49 96 (63 ) Income Tax Expense – Continuing Operations $ 3,054 $ 5,897 $ 6,848 $ 12,260 Effective Income Tax Rate – Continuing Operations 14.0 % 26.1 % 13.2 % 25.3 % |
Summary of Income Tax Contingencies [Table Text Block] | (in thousands) 2018 2017 Balance on January 1 $ 684 $ 891 Decreases Related to Tax Positions for Prior Years (44 ) -- Increases Related to Tax Positions for Current Year 72 147 Uncertain Positions Resolved During Year -- -- Balance on June 30 $ 712 $ 1,038 |
Note 1 - Summary of Significa31
Note 1 - Summary of Significant Accounting Policies (Details Textual) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Mar. 31, 2019USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Goodwill, Period Increase (Decrease), Total | $ 0 | |||
Pro Forma [Member] | Accounting Standards Update 2017-07 [Member] | ||||
Postretirement Benefit Plan, Nonservice Costs Capitalized to Plant in Service During Fiscal Year | $ 800 | |||
Postretirement Benefit Plan, Nonservice Costs Included in Operating Expense During Fiscal Year | $ 5,600 | $ 5,100 | ||
Scenario, Forecast [Member] | Accounting Standards Update 2018-02 [Member] | ||||
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect | $ 800 | |||
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 | $ 55,700 | |||
Variable Interest Entity Reporting Entity Involvement, Maximum Loss Exposure, Percentage | 35.00% | |||
Plastics [Member] | ||||
Number of Customers Under Build and Hold Agreements | 1 | |||
Goodwill, Period Increase (Decrease), Total |
Note 1 - Summary of Significa32
Note 1 - Summary of Significant Accounting Policies - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Fair Value, Inputs, Level 1 [Member] | ||
Total Assets | $ 2,178 | $ 2,108 |
Fair Value, Inputs, Level 1 [Member] | Equity Funds [Member] | ||
Investments | 1,233 | 1,285 |
Fair Value, Inputs, Level 1 [Member] | Corporate Debt Securities [Member] | ||
Investments | ||
Fair Value, Inputs, Level 1 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Investments | ||
Fair Value, Inputs, Level 1 [Member] | Money Market and Mutual Funds [Member] | ||
Other Assets | 945 | 823 |
Fair Value, Inputs, Level 2 [Member] | ||
Total Assets | 7,157 | 7,160 |
Fair Value, Inputs, Level 2 [Member] | Equity Funds [Member] | ||
Investments | ||
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | ||
Investments | 5,630 | 5,373 |
Fair Value, Inputs, Level 2 [Member] | Government-backed and Government-sponsored Enterprises' Debt Securities [Member] | ||
Investments | 1,527 | 1,787 |
Fair Value, Inputs, Level 2 [Member] | Money Market and Mutual Funds [Member] | ||
Other Assets |
Note 1 - Summary of Significa33
Note 1 - Summary of Significant Accounting Policies - Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Finished Goods | $ 27,140 | $ 26,605 |
Work in Process | 17,000 | 14,222 |
Raw Material, Fuel and Supplies | 46,295 | 47,207 |
Total Inventories | $ 90,435 | $ 88,034 |
Note 1 - Summary of Significa34
Note 1 - Summary of Significant Accounting Policies - Summary of Changes to Goodwill by Business Segment (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Gross Balance | $ 37,572 | |
Accumulated Impairments | ||
Balance | $ 37,572 | 37,572 |
Adjustments to Goodwill | 0 | |
Manufacturing [Member] | ||
Gross Balance | 18,270 | |
Accumulated Impairments | ||
Balance | 18,270 | 18,270 |
Adjustments to Goodwill | ||
Plastics [Member] | ||
Gross Balance | 19,302 | |
Accumulated Impairments | ||
Balance | 19,302 | $ 19,302 |
Adjustments to Goodwill |
Note 1 - Summary of Significa35
Note 1 - Summary of Significant Accounting Policies - Components of Intangible Assets (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Gross Carrying Amount | $ 23,235 | $ 23,235 |
Accumulated Amortization | 10,160 | 9,470 |
Net Carrying Amount | 13,075 | 13,765 |
Customer Relationships [Member] | ||
Gross Carrying Amount | 22,491 | 22,491 |
Accumulated Amortization | 9,560 | 8,994 |
Net Carrying Amount | $ 12,931 | $ 13,497 |
Customer Relationships [Member] | Minimum [Member] | ||
Remaining Amortization Periods (Month) | 1 year 180 days | 2 years |
Customer Relationships [Member] | Maximum [Member] | ||
Remaining Amortization Periods (Month) | 17 years 60 days | 17 years 240 days |
Covenant Not to Compete [Member] | ||
Gross Carrying Amount | $ 590 | $ 590 |
Accumulated Amortization | 557 | 459 |
Net Carrying Amount | $ 33 | $ 131 |
Remaining Amortization Periods (Month) | 60 days | 240 days |
Other Intangible Assets [Member] | ||
Gross Carrying Amount | $ 154 | $ 154 |
Accumulated Amortization | 43 | 17 |
Net Carrying Amount | $ 111 | $ 137 |
Remaining Amortization Periods (Month) | 2 years 60 days | 2 years 240 days |
Note 1 - Summary of Significa36
Note 1 - Summary of Significant Accounting Policies - Amortization Expense for Intangible Assets (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Amortization Expense – Intangible Assets | $ 345 | $ 333 | $ 690 | $ 665 |
Note 1 - Summary of Significa37
Note 1 - Summary of Significant Accounting Policies - Estimated Annual Amortization Expense for Intangible Assets (Details) $ in Thousands | Jun. 30, 2018USD ($) |
2,018 | $ 1,315 |
2,019 | 1,184 |
2,020 | 1,133 |
2,021 | 1,099 |
2,022 | $ 1,099 |
Note 1 - Summary of Significa38
Note 1 - Summary of Significant Accounting Policies - Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Jun. 30, 2017 |
Transactions Related to Capital Additions not Settled in Cash | $ 11,564 | $ 16,312 |
Note 2 - Segment Information (D
Note 2 - Segment Information (Details Textual) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Number of Reportable Segments | 3 | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Electric [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 11.70% | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Recreational Vehicles [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 24.30% | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Manufacturing [Member] | Customer that Manufactures and Sells Lawn and Garden Equipment [Member] | |||||
Number of Customers | 1 | ||||
Concentration Risk, Percentage | 12.00% | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | |||||
Number of Customers | 2 | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer One [Member] | |||||
Concentration Risk, Percentage | 20.60% | ||||
Sales Revenue, Segment [Member] | Customer Concentration Risk [Member] | Plastics [Member] | Customer Two [Member] | |||||
Concentration Risk, Percentage | 17.80% | ||||
Sales Revenue, Net [Member] | UNITED STATES | |||||
Concentration Risk, Percentage | 98.20% | 98.30% | 98.30% | 98.30% |
Note 2 - Segment Information -
Note 2 - Segment Information - Information on Continuing Operations for Business Segments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Operating Revenues | $ 226,348 | $ 212,086 | $ 467,614 | $ 426,203 | |
Interest charges | 7,676 | 7,527 | 15,048 | 14,989 | |
Income Taxes | 3,054 | 5,897 | 6,848 | 12,260 | |
Net Income (Loss) | 18,696 | 16,778 | 44,911 | 36,363 | |
Assets | 2,011,247 | 2,011,247 | $ 2,004,278 | ||
Discontinued Operations [Member] | |||||
Net Income (Loss) | 61 | 117 | |||
Operating Segments [Member] | Electric [Member] | |||||
Revenue from Contracts with Customers | 13,351 | 14,797 | 26,996 | 27,266 | |
Regulated operating revenues | 103,725 | 102,236 | 226,690 | 220,787 | |
Interest charges | 6,687 | 6,439 | 13,077 | 12,825 | |
Income Taxes | 611 | 2,442 | 2,709 | 8,504 | |
Net Income (Loss) | 10,600 | 10,134 | 27,268 | 25,694 | |
Assets | 1,687,799 | 1,687,799 | 1,690,224 | ||
Operating Segments [Member] | Electric [Member] | Retail [Member] | |||||
Revenue from Contracts with Customers | 89,400 | 86,679 | 198,580 | 193,133 | |
Changes in Accrued ARP Revenues | (1,565) | (424) | (2,440) | (1,663) | |
Regulated operating revenues | 87,835 | 86,255 | 196,140 | 191,470 | |
Operating Segments [Member] | Electric [Member] | Wholesale [Member] | |||||
Revenue from Contracts with Customers | 2,539 | 1,184 | 3,554 | 2,051 | |
Operating Segments [Member] | Manufacturing [Member] | |||||
Revenue from Contracts with Customers | 68,154 | 59,304 | 136,816 | 117,721 | |
Interest charges | 555 | 553 | 1,109 | 1,107 | |
Income Taxes | 1,018 | 1,573 | 2,241 | 2,628 | |
Net Income (Loss) | 3,583 | 2,955 | 7,747 | 5,127 | |
Assets | 181,094 | 181,094 | 167,023 | ||
Operating Segments [Member] | Manufacturing [Member] | Metal Parts and Tooling [Member] | |||||
Revenue from Contracts with Customers | 57,388 | 49,450 | 114,315 | 97,528 | |
Operating Segments [Member] | Manufacturing [Member] | Plastic Products [Member] | |||||
Revenue from Contracts with Customers | 7,961 | 7,376 | 18,196 | 16,928 | |
Operating Segments [Member] | Manufacturing [Member] | Manufactured Product, Other [Member] | |||||
Revenue from Contracts with Customers | 2,805 | 2,478 | 4,305 | 3,265 | |
Operating Segments [Member] | Plastics [Member] | |||||
Revenue from Contracts with Customers | 54,476 | 50,551 | 104,129 | 87,708 | |
Interest charges | 160 | 173 | 310 | 326 | |
Income Taxes | 2,207 | 2,858 | 4,621 | 4,248 | |
Net Income (Loss) | 6,229 | 4,637 | 13,073 | 7,074 | |
Assets | 99,205 | 99,205 | 87,230 | ||
Corporate and Eliminations [Member] | |||||
Interest charges | 274 | 362 | 552 | 731 | |
Income Taxes | (782) | (976) | (2,723) | (3,120) | |
Net Income (Loss) | (1,716) | (1,009) | (3,177) | (1,649) | |
Assets | 43,149 | 43,149 | $ 59,801 | ||
Intersegment Eliminations [Member] | |||||
Regulated operating revenues | $ (7) | $ (5) | $ (21) | $ (13) |
Note 3 - Rate and Regulatory 41
Note 3 - Rate and Regulatory Matters (Details Textual) | Nov. 01, 2018USD ($) | Jul. 06, 2018USD ($) | Apr. 20, 2018USD ($) | Mar. 23, 2018USD ($) | Mar. 22, 2018USD ($) | Dec. 20, 2017USD ($) | Nov. 17, 2017USD ($) | Nov. 01, 2017USD ($) | Sep. 28, 2016 | May 25, 2016 | Feb. 12, 2015 | Nov. 06, 2014 | Nov. 12, 2013 | Jun. 01, 2011USD ($) | Jun. 30, 2016 | Dec. 22, 2015 | Mar. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2018 | Dec. 31, 2017USD ($) | Jul. 03, 2018USD ($) | Jun. 13, 2018USD ($) | Mar. 01, 2018USD ($) | Nov. 02, 2017USD ($) | Oct. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Apr. 16, 2016 | Apr. 15, 2016 | Nov. 25, 2009USD ($) |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | ||||||||||||||||||||||||||||
Minnesota [Member] | |||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | $ 4,100,000 | ||||||||||||||||||||||||||||
NORTH DAKOTA | |||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 800,000 | ||||||||||||||||||||||||||||
South Dakota [Member] | |||||||||||||||||||||||||||||
Accrued Refund Liabilities Resulting from Tax Rate Reduction | 700,000 | ||||||||||||||||||||||||||||
Scenario, Forecast [Member] | |||||||||||||||||||||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||||||||
Contract with Customer, Refund Liability, Total | 1,600,000 | $ 2,700,000 | |||||||||||||||||||||||||||
Current Return on Equity Used in Transmission Rates | 10.32% | 12.38% | 10.32% | ||||||||||||||||||||||||||
Proposed Reduced Return on Equity Used in Transmission Rates | 8.67% | 9.15% | 9.70% | ||||||||||||||||||||||||||
Additional Incentive Basis Point | 0.50% | ||||||||||||||||||||||||||||
Expected Percentage of Return on Equity | 10.82% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||
Estimated Interim Rate Refund | $ 9,000,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 7.5056% | 8.61% | |||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 9.41% | 10.74% | |||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Environmental Cost Recovery Rider [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Customer Refund | $ 900,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member] | |||||||||||||||||||||||||||||
Amount Credited to Customers, Subject to Recovery Should the Courts Decision Be Upheld | 2,000,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Transmission Cost Recovery Rider [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Customer Refund | $ 1,400,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | ECR and TCR Riders [Member] | The 2016 General Rate Case [Member] | |||||||||||||||||||||||||||||
Revenues Collected Under Riders, Subject to Refund, Period of Refund | 1 year | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | |||||||||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Twelve Months | 13.50% | ||||||||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Year Two | 12.00% | ||||||||||||||||||||||||||||
Utility Incentive Percentage in Next Rolling Year Three | 10.00% | ||||||||||||||||||||||||||||
Assumed Savings of Utility | 1.70% | ||||||||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year One | 40.00% | ||||||||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year Two | 35.00% | ||||||||||||||||||||||||||||
Financial Incentive, Maximum Percentage of Spending, Year Three | 30.00% | ||||||||||||||||||||||||||||
Financial Incentives Recognized During Period | $ 2.60 | $ 2,600,000 | |||||||||||||||||||||||||||
Percentage Decrease in Energy Savings | 10.00% | ||||||||||||||||||||||||||||
Amount Of Financial Incentive Requested | $ 2,900,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Conservation Improvement Program [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||
Amount Of Financial Incentive Requested | $ 2,600,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Renewable Resource Adjustment [Member] | |||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 1,300,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Minnesota Public Utilities Commission [Member] | Renewable Resource Adjustment [Member] | Scenario, Forecast [Member] | |||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 5,800,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member] | |||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 7.97% | ||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.30% | 10.30% | |||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7,100,000 | $ 13,100,000 | |||||||||||||||||||||||||||
General Rate Revenue Increase Requested | $ 13,100,000 | ||||||||||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Requested | 8.72% | ||||||||||||||||||||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 12,800,000 | ||||||||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Decrease in Amount | $ 4,500,000 | ||||||||||||||||||||||||||||
Public Utilities, Interim Rate Requirement, Amount | $ 8,300,000 | ||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.80% | ||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease | $ 6,000,000 | ||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Tax Reform | 4,800,000 | ||||||||||||||||||||||||||||
General Rate Revenue Increase Requested, Decrease, Amount Related to Updates Other Than Tax Reform | $ 1,200,000 | ||||||||||||||||||||||||||||
Contract with Customer, Refund Liability, Total | $ 1,800,000 | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2017 General Rate Case [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 5,400,000 | ||||||||||||||||||||||||||||
Percentage of Requested Allowed Rate of Return on Equity | 9.77% | ||||||||||||||||||||||||||||
Equity to Total Capitalization Ratio Basis for Return on Equity | 52.50% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | North Dakota Public Service Commission [Member] | The 2008 General Rate Case [Member] | |||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Rate Base | 8.62% | ||||||||||||||||||||||||||||
Percentage of Allowed Rate of Return on Equity | 10.75% | ||||||||||||||||||||||||||||
General Rate Revenue Increase Requested | $ 3,600,000 | ||||||||||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Requested | 3.00% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2018 General Rate Case [Member] | |||||||||||||||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 3,300,000 | ||||||||||||||||||||||||||||
Increase in Annual Non-fuel Rates Requested, Step One, Percentage | 10.10% | ||||||||||||||||||||||||||||
Increase in Annual Non-fuel Rates Requested, Step Two, Percentage | 1.70% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | South Dakota Public Utilities Commission [Member] | The 2010 General Rate Case [Member] | |||||||||||||||||||||||||||||
Public Utilities General Rate Revenue Increase Approved | $ 643,000 | ||||||||||||||||||||||||||||
Percentage of Increase in Base Rate Revenue Approved | 2.32% | ||||||||||||||||||||||||||||
Public Utilities Allowed Rate of Return on Rate Base Subsequent to Approval of Increase in Base Rate | 8.50% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Big Stone South - Ellendale MVP [Member] | Federal Energy Regulatory Commission [Member] | |||||||||||||||||||||||||||||
Expanded Capacity of Projects | 345 | ||||||||||||||||||||||||||||
Extended Distance of Transmission Line | 163 | ||||||||||||||||||||||||||||
Current Projected Cost | $ 99,400,000 | ||||||||||||||||||||||||||||
Percentage of Assets of Project | 100.00% | ||||||||||||||||||||||||||||
Otter Tail Power Company [Member] | Big Stone South - Brookings MVP [Member] | |||||||||||||||||||||||||||||
Expanded Capacity of Projects | 345 | ||||||||||||||||||||||||||||
Extended Distance of Transmission Line | 70 | ||||||||||||||||||||||||||||
Current Projected Cost | $ 72,500,000 | ||||||||||||||||||||||||||||
Percentage of Assets of Project | 100.00% |
Note 3 - Rate and Regulatory 42
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 | 6 Months Ended | |
Jun. 30, 2018USD ($)kWh | ||
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2017 Incentive and Cost Recovery [Member] | ||
R - Request Date | Mar. 30, 2018 | |
Effective Date Requested or Approved | Oct. 1, 2018 | |
Annual Revenue | $ 10,300 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.006 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2016 Incentive and Cost Recovery [Member] | ||
Effective Date Requested or Approved | Oct. 1, 2017 | |
Annual Revenue | $ 9,868 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | |
A - Approval Date | Sep. 15, 2017 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | The 2015 Incentive and Cost Recovery [Member] | ||
Effective Date Requested or Approved | Oct. 1, 2016 | |
Annual Revenue | $ 8,590 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00275 | |
A - Approval Date | Jul. 19, 2016 | |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | [1] |
Annual Revenue | $ (3,311) | [1] |
A - Approval Date | Oct. 30, 2017 | [1] |
Rate | Various | [1] |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Sep. 1, 2016 | |
Annual Revenue | $ 4,736 | |
A - Approval Date | Jul. 5, 2016 | |
Rate | Various | |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Apr. 1, 2016 | |
Annual Revenue | $ 7,203 | |
A - Approval Date | Mar. 9, 2016 | |
Rate | Various | |
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ (1,943) | |
A - Approval Date | Oct. 30, 2017 | |
Rate of base | (0.935%) | |
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Sep. 1, 2016 | |
Annual Revenue | $ 11,884 | |
A - Approval Date | Jul. 5, 2016 | |
Rate of base | 6.927% | |
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Annual Update [Member] | ||
R - Request Date | Jul. 3, 2018 | |
Effective Date Requested or Approved | Dec. 1, 2018 | |
Annual Revenue | ||
Rate of base | 0.00% | |
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ 1,279 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00049 | |
A - Approval Date | Oct. 30, 2017 | |
Minnesota [Member] | Renewable Resource Adjustment [Member] | The 2018 Annual Update [Member] | ||
R - Request Date | Jun. 14, 2018 | |
Effective Date Requested or Approved | Nov. 1, 2018 | |
Annual Revenue | $ 5,886 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00244 | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2017 | |
Annual Revenue | $ 6,916 | |
A - Approval Date | Dec. 14, 2016 | |
Rate | Various | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 7,469 | |
A - Approval Date | Feb. 27, 2018 | |
Rate | Various | |
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 7,959 | |
A - Approval Date | Nov. 29, 2017 | |
Rate | Various | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 8,537 | |
A - Approval Date | Dec. 20, 2017 | |
Rate of base | 6.629% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Jul. 1, 2016 | |
Annual Revenue | $ 10,359 | |
A - Approval Date | Jun. 22, 2016 | |
Rate of base | 7.904% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 7,718 | |
A - Approval Date | Feb. 27, 2018 | |
Rate of base | 5.593% | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Aug. 1, 2017 | |
Annual Revenue | $ 9,917 | |
A - Approval Date | Jul. 12, 2017 | |
Rate of base | 7.633% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2017 Rate Reset [Member] | ||
Effective Date Requested or Approved | Jan. 1, 2018 | |
Annual Revenue | $ 9,989 | |
A - Approval Date | Dec. 20, 2017 | |
Rate of base | 7.756% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Apr. 1, 2017 | |
Annual Revenue | $ 9,156 | |
A - Approval Date | Mar. 15, 2017 | |
Rate of base | 7.005% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Jul. 1, 2016 | |
Annual Revenue | $ 9,262 | |
A - Approval Date | Jun. 22, 2016 | |
Rate of base | 7.573% | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | The 2018 Rate Reset for Effect of TCJA [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 9,650 | |
A - Approval Date | Feb. 27, 2018 | |
Rate of base | 7.493% | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2017 | |
Annual Revenue | $ 2,053 | |
A - Approval Date | Feb. 17, 2017 | |
Rate | Various | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2015 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2016 | |
Annual Revenue | $ 1,895 | |
A - Approval Date | Feb. 12, 2016 | |
Rate | Various | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Mar. 1, 2018 | |
Annual Revenue | $ 1,779 | |
A - Approval Date | Feb. 28, 2018 | |
Rate | Various | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2016 Annual Update [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2016 | |
Annual Revenue | $ 2,238 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00536 | |
A - Approval Date | Oct. 26, 2016 | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | The 2017 Annual Update [Member] | ||
Effective Date Requested or Approved | Nov. 1, 2017 | |
Annual Revenue | $ 2,082 | |
Rate rider rate (Kilowatt-Hour) | kWh | 0.00483 | |
A - Approval Date | Oct. 13, 2017 | |
[1] | Approved on a provisional basis in the Minnesota general rate case docket and subject to revision in a separate docket. |
Note 3 - Rate and Regulatory 43
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, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||
Revenues recorded under rate riders | $ 8,512 | $ 12,806 | $ 18,628 | $ 27,813 | |
Minnesota [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Revenues recorded under rate riders | [1] | 2,368 | 2,102 | 4,884 | 4,068 |
Minnesota [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 1,273 | 3,443 | |||
Revenues recorded under rate riders | (458) | (487) | |||
Minnesota [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 2,812 | 5,636 | |||
Revenues recorded under rate riders | (18) | (49) | |||
Minnesota [Member] | Renewable Resource Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 659 | 1,184 | |||
North Dakota [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 1,165 | 1,384 | 3,227 | 3,895 | |
North Dakota [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 1,830 | 2,388 | 3,651 | 4,876 | |
North Dakota [Member] | Renewable Resource Adjustment [Member] | |||||
Revenues recorded under rate riders | 2,079 | 1,839 | 4,046 | 3,609 | |
South Dakota [Member] | Conservation Improvement Program Costs and Incentives [Member] | |||||
Revenues recorded under rate riders | 122 | 176 | 351 | 416 | |
South Dakota [Member] | Transmission Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | 250 | 287 | 786 | 728 | |
South Dakota [Member] | Environmental Cost Recovery Rider [Member] | |||||
Revenues recorded under rate riders | $ 515 | $ 545 | $ 1,035 | $ 1,142 | |
[1] | Includes MNCIP costs recovered in base rates. |
Note 4 - Regulatory Assets an44
Note 4 - Regulatory Assets and Liabilities (Details Textual) | 6 Months Ended |
Jun. 30, 2018 | |
Regulatory Noncurrent Asset, Remaining Recovery Period | 14 years 90 days |
Note 4 - Regulatory Assets an45
Note 4 - Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | ||
Regulatory Assets - Current | $ 17,914 | $ 22,551 | |
Regulatory Assets - Long -Term | 123,631 | 129,576 | |
Regulatory Assets - Total | 141,545 | 152,127 | |
Regulatory Liabilities - Current | 7,248 | 9,688 | |
Regulatory Liabilities - Long -Term | 228,163 | 232,893 | |
Regulatory Liabilities - Total | 235,411 | 242,581 | |
Net Regulatory Asset Position - Current | 10,666 | 12,863 | |
Net Regulatory Asset Position - Long-Term | (104,532) | (103,317) | |
Net Regulatory Asset/(Liability) Position | (93,866) | (90,454) | |
Deferred Income Taxes [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 147,858 | 149,052 | |
Regulatory Liabilities - Total | $ 147,858 | $ 149,052 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 79,835 | 83,100 | |
Regulatory Liabilities - Total | $ 79,835 | $ 83,100 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Refundable Fuel Clause Adjustment Revenues [Member] | |||
Regulatory Liabilities - Current | $ 4,972 | $ 5,778 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 4,972 | $ 5,778 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
Minnesota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 716 | $ 1,667 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 716 | $ 1,667 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 120 days | 330 days | |
North Dakota Renewable Resource Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 394 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 394 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 270 days | ||
North Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 319 | $ 349 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 319 | $ 349 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
Minnesota Southwest Power Pool Transmission Cost Recovery Tracker [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 316 | ||
Regulatory Liabilities - Total | $ 316 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | ||
Minnesota Southwest Power Pool Transmission Cost Tracker Refund [Member] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 609 | ||
Regulatory Liabilities - Total | $ 609 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year 300 days | ||
South Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 308 | $ 187 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 308 | $ 187 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
North Dakota Environmental Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 240 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 240 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | ||
South Dakota Transmission Cost Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 231 | $ 151 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 231 | $ 151 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year | 1 year | |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Liabilities - Current | $ 61 | $ 132 | |
Regulatory Liabilities - Long -Term | 24 | 48 | |
Regulatory Liabilities - Total | $ 85 | $ 180 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 1 year 180 days | 2 years | |
Other [Member] | |||
Regulatory Liabilities - Current | $ 6 | $ 5 | |
Regulatory Liabilities - Long -Term | 81 | 84 | |
Regulatory Liabilities - Total | $ 87 | $ 89 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 15 years 180 days | 16 years | |
Revenue for Rate Case Expenses Subject to Refund - Minnesota [Member] | |||
Regulatory Liabilities - Current | $ 208 | ||
Regulatory Liabilities - Long -Term | 49 | ||
Regulatory Liabilities - Total | $ 49 | $ 208 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 120 days | ||
Minnesota Renewable Resource Recovery Rider Accrued Refund [Member] | |||
Regulatory Liabilities - Current | $ 1 | $ 409 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 1 | $ 409 | |
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 120 days | 1 year | |
Minnesota Transmission Cost Recovery Rider Accrued Refund [member] | |||
Regulatory Liabilities - Current | $ 802 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 802 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period (Month) | 300 days | ||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits [Member] | |||
Regulatory Assets - Current | [1] | $ 9,090 | $ 9,090 |
Regulatory Assets - Long -Term | [1] | 107,946 | 112,487 |
Regulatory Assets - Total | [1] | $ 117,036 | $ 121,577 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
Conservation Improvement Program Costs and Incentives [Member] | |||
Regulatory Assets - Current | [2] | $ 3,927 | $ 7,385 |
Regulatory Assets - Long -Term | [2] | 4,163 | 2,774 |
Regulatory Assets - Total | [2] | $ 8,090 | $ 10,159 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 2 years 90 days | 1 year 270 days |
Accumulated ARO Accretion/Depreciation Adjustment [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 6,907 | 6,651 |
Regulatory Assets - Total | [1] | $ 6,907 | $ 6,651 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Deferred Marked-to-Market Losses [Member] | |||
Regulatory Assets - Current | [1] | $ 2,862 | $ 4,063 |
Regulatory Assets - Long -Term | [1] | 1,574 | 2,405 |
Regulatory Assets - Total | [1] | $ 4,436 | $ 6,468 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 2 years 180 days | 3 years |
Big Stone II Unrecovered Project Costs - Minnesota [Member] | |||
Regulatory Assets - Current | [1] | $ 665 | $ 650 |
Regulatory Assets - Long -Term | [1] | 1,296 | 1,636 |
Regulatory Assets - Total | [1] | $ 1,961 | $ 2,286 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 2 years 300 days | 3 years 120 days |
Debt Reacquisition Premiums [Member] | |||
Regulatory Assets - Current | [1] | $ 231 | $ 254 |
Regulatory Assets - Long -Term | [1] | 856 | 960 |
Regulatory Assets - Total | [1] | $ 1,087 | $ 1,214 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 14 years 90 days | 14 years 270 days |
Minnesota Energy Intensive Trade Exposed Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [1] | $ 513 | $ 75 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 513 | $ 75 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year | 1 year |
Big Stone II Unrecovered Project Costs - South Dakota [Member] | |||
Regulatory Assets - Current | [1] | $ 100 | $ 100 |
Regulatory Assets - Long -Term | [1] | 392 | 442 |
Regulatory Assets - Total | [1] | $ 492 | $ 542 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 4 years 330 days | 5 years 150 days |
Nonservice Costs Components of Postretirement Benefits Capitalized for Ratemaking Purposes and Subject to Deferred Recovery [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 422 | |
Regulatory Assets - Total | [1] | $ 422 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | |
North Dakota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 303 | $ 309 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 303 | $ 309 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year | 1 year |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up [Member] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 75 | 1,985 |
Regulatory Assets - Total | [1] | $ 75 | $ 1,985 |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 1 year 180 days | 2 years |
Minnesota Transmission Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 223 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 223 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year 180 days | |
North Dakota Renewable Resource Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 206 | |
Regulatory Assets - Long -Term | [2] | 236 | |
Regulatory Assets - Total | [2] | $ 442 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year 90 days | |
Minnesota Deferred Rate Case Expenses Subject to Recovery [Member] | |||
Regulatory Assets - Current | [1] | $ 267 | |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 267 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [1] | 120 days | |
North Dakota Environmental Cost Recovery Rider Accrued Revenues [Member] | |||
Regulatory Assets - Current | [2] | $ 152 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 152 | |
Regulatory Assets - Remaining Recovery/Refund Period (Month) | [2] | 1 year | |
[1] | Costs subject to recovery excluding a rate of return. | ||
[2] | Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Note 5 - Reconciliation of Co46
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details Textual) - $ / shares | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | May 03, 2018 | |
Maximum per Share Differences Between Basic and Diluted Earnings per Share in Total or from Continuing or Discontinued Operations | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |
Dividend Reinvestment and Share Purchase Plan [Member] | |||||
Shelf Registration, Shares | 1,500,000 |
Note 5 - Reconciliation of Co47
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Balance, beginning | $ 696,892 | |||
Common Stock Issuances, Net of Expenses | (93) | |||
Common Stock Retirements | (2,450) | |||
Net Income | $ 18,696 | $ 16,778 | 44,911 | $ 36,363 |
Other Comprehensive Loss | (340) | |||
Employee Stock Incentive Plans Expense | 2,253 | |||
Common Dividends ($0.67 per share) | (26,592) | |||
Balance, ending | 714,581 | 714,581 | ||
Par Value, Common Shares [Member] | ||||
Balance, beginning | 197,787 | |||
Common Stock Issuances, Net of Expenses | 767 | |||
Common Stock Retirements | (297) | |||
Net Income | ||||
Other Comprehensive Loss | ||||
Employee Stock Incentive Plans Expense | ||||
Common Dividends ($0.67 per share) | ||||
Balance, ending | 198,257 | 198,257 | ||
Premium on Common Shares [Member] | ||||
Balance, beginning | 343,450 | |||
Common Stock Issuances, Net of Expenses | (860) | |||
Common Stock Retirements | (2,153) | |||
Net Income | ||||
Other Comprehensive Loss | ||||
Employee Stock Incentive Plans Expense | 2,253 | |||
Common Dividends ($0.67 per share) | ||||
Balance, ending | 342,690 | 342,690 | ||
Retained Earnings [Member] | ||||
Balance, beginning | 161,286 | |||
Common Stock Issuances, Net of Expenses | ||||
Common Stock Retirements | ||||
Net Income | 44,911 | |||
Other Comprehensive Loss | ||||
Employee Stock Incentive Plans Expense | ||||
Common Dividends ($0.67 per share) | (26,592) | |||
Balance, ending | 179,605 | 179,605 | ||
Accumulated Other Comprehensive Income/(Loss) [Member] | ||||
Balance, beginning | (5,631) | |||
Common Stock Issuances, Net of Expenses | ||||
Common Stock Retirements | ||||
Net Income | ||||
Other Comprehensive Loss | (340) | |||
Employee Stock Incentive Plans Expense | ||||
Common Dividends ($0.67 per share) | ||||
Balance, ending | $ (5,971) | $ (5,971) |
Note 5 - Reconciliation of Co48
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Schedule of Reconciliation of Stockholders' Equity (Details) (Parentheticals) - $ / shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Dividends Declared Per Common Share (in dollars per share) | $ 0.335 | $ 0.32 | $ 0.67 | $ 0.64 |
Note 5 - Reconciliation of Co49
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Company's Common Shares (Details) | 6 Months Ended |
Jun. 30, 2018shares | |
Common Shares Outstanding, beginning balance (in shares) | 39,557,491 |
Issuances: | |
Executive Stock Performance Awards (2015 shares earned) (in shares) | 114,648 |
Vesting of Restricted Stock Units (in shares) | 19,950 |
Restricted Stock Issued to Directors (in shares) | 18,200 |
Directors Deferred Compensation (in shares) | 578 |
Retirements: | |
Shares Withheld for Individual Income Tax Requirements (in shares) | (59,431) |
Common Shares Outstanding, ending balance (in shares) | 39,651,436 |
Note 5 - Reconciliation of Co50
Note 5 - Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of Weighted Average Common Shares Outstanding (Details) - shares | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Weighted Average Common Shares Outstanding – Basic (in shares) | 39,605,717 | 39,462,865 | 39,578,296 | 39,406,834 |
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits: | ||||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance (in shares) | 202,643 | 173,974 | 212,902 | 187,806 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees (in shares) | 57,616 | 50,087 | 58,373 | 53,980 |
Nonvested Restricted Shares (in shares) | 10,733 | 12,719 | 19,188 | 19,894 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors (in shares) | 2,360 | 2,854 | 2,617 | 3,098 |
Total Dilutive Shares (in shares) | 273,352 | 239,634 | 293,080 | 264,778 |
Weighted Average Common Shares Outstanding – Diluted (in shares) | 39,879,069 | 39,702,499 | 39,871,376 | 39,671,612 |
Note 6 - Share-based Payments51
Note 6 - Share-based Payments (Details Textual) - USD ($) $ in Millions | Feb. 05, 2018 | Jun. 30, 2018 |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Total | $ 6.2 | |
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition | 2 years 73 days | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 54,000 | |
Period Specified for Average Adjusted Return | 3 years | |
Number of Trading Days | 20 days | |
Number of Shares Authorized for Actual Payment | 81,000 | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Minimum [Member] | ||
Percentage of Target Amount as Actual Payment | 0.00% | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Maximum [Member] | ||
Percentage of Target Amount as Actual Payment | 150.00% | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,000 | |
Stock Performance Awards [Member] | Executive Officer [Member] | The 2014 Stock Incentive Plan [Member] | Share-based Compensation Award, Tranche Two [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 27,000 |
Note 6 - Share-based Payments -
Note 6 - Share-based Payments - Stock Incentive Awards Granted to Officers Under the 2014 Stock Incentive Plan (Details) - The 2014 Stock Incentive Plan [Member] | 6 Months Ended |
Jun. 30, 2018$ / sharesshares | |
Stock Performance Awards [Member] | Executive Officer [Member] | |
Shares/units granted, grant date | Feb. 5, 2018 |
Performance Shares [Member] | Executive Officer [Member] | |
Shares/units granted (in shares) | shares | 54,000 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 35.73 |
Shares/units granted, vesting date | Dec. 31, 2020 |
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | |
Shares/units granted, grant date | Feb. 5, 2018 |
Shares/units granted (in shares) | shares | 15,200 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 41.325 |
Shares/units granted, vesting date | Feb. 6, 2022 |
Restricted Stock Units (RSUs) [Member] | Key Employees [Member] | |
Shares/units granted, grant date | Apr. 9, 2018 |
Shares/units granted (in shares) | shares | 12,945 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 38.45 |
Shares/units granted, vesting date | Apr. 8, 2022 |
Restricted Stock Units (RSUs) [Member] | Key Employee [Member] | |
Shares/units granted, grant date | Jun. 20, 2018 |
Shares/units granted (in shares) | shares | 1,000 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 42.46 |
Shares/units granted, vesting date | Apr. 8, 2022 |
Restricted Stock [Member] | Nonemployee Directors [Member] | |
Shares/units granted, grant date | Apr. 9, 2018 |
Shares/units granted (in shares) | shares | 18,200 |
Shares/units granted, weighted average grant-date fair value per award (in dollars per share) | $ / shares | $ 43.40 |
Shares/units granted, vesting date | Apr. 8, 2021 |
Note 6 - Share-based Payments53
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, 2018 | |
Executive Officer [Member] | Restricted Stock Units (RSUs) [Member] | |
Shares/units granted, vesting percentage | 25.00% |
Key Employees [Member] | Restricted Stock Units (RSUs) [Member] | |
Shares/units granted, vesting percentage | 100.00% |
Key Employee [Member] | Restricted Stock Units (RSUs) [Member] | |
Shares/units granted, vesting percentage | 100.00% |
Nonemployee Directors [Member] | Restricted Stock [Member] | |
Shares/units granted, vesting percentage | 33.00% |
Note 6 - Share-based Payments54
Note 6 - Share-based Payments - Amounts of Compensation Expense Recognized Under Stock-based Payment Programs (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Stock compensation expense | $ 1,107 | $ 770 | $ 2,253 | $ 1,920 |
Stock Performance Awards [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 668 | 425 | 1,319 | 1,074 |
Restricted Stock Units (RSUs) [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 173 | 104 | 422 | 368 |
Restricted Stock Units (RSUs) [Member] | Key Employees [Member] | ||||
Stock compensation expense | 101 | 81 | 165 | 168 |
Restricted Stock [Member] | Executive Officer [Member] | ||||
Stock compensation expense | 16 | 16 | 38 | |
Restricted Stock [Member] | Nonemployee Directors [Member] | ||||
Stock compensation expense | $ 165 | $ 144 | $ 331 | $ 272 |
Note 7 - Retained Earnings an55
Note 7 - Retained Earnings and Dividend Restriction (Details Textual) - USD ($) | May 01, 2018 | Jun. 30, 2018 | Dec. 31, 2017 |
Capitalization, Long-term Debt and Equity, Total | $ 1,304,541,000 | $ 1,187,272,000 | |
Otter Tail Power Company [Member] | |||
Equity to Total Capitalization Ratio | 52.50% | ||
Net Assets Restricted from Distribution | $ 473,000,000 | ||
Capitalization, Long-term Debt and Equity, Total | $ 1,178,024,000 | ||
Otter Tail Power Company [Member] | If Approved [Member] | |||
Capitalization, Long-term Debt and Equity, Total | $ 1,204,416,000 | ||
Otter Tail Power Company [Member] | Minimum [Member] | |||
Equity to Total Capitalization Ratio | 47.40% | ||
Otter Tail Power Company [Member] | Minimum [Member] | Minnesota Public Utilities Commission [Member] | |||
Public Utilities, Requested Equity Capital Structure, Percentage | 47.90% | ||
Otter Tail Power Company [Member] | Maximum [Member] | |||
Equity to Total Capitalization Ratio | 58.00% | ||
Otter Tail Power Company [Member] | Maximum [Member] | Minnesota Public Utilities Commission [Member] | |||
Public Utilities, Requested Equity Capital Structure, Percentage | 58.50% |
Note 8 - Commitments and Cont56
Note 8 - Commitments and Contingencies (Details Textual) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($) | |
Loss Contingency, Estimate of Possible Loss | $ 1,000,000 | |
Agreement to Lease Rail Cars for Transporting Coal to Hoot Lake Plant [Member] | ||
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year | 216,000 | |
Operating Leases, Future Minimum Payments, Due in Two Years | 324,000 | |
Operating Leases, Future Minimum Payments, Due in Three Years | 324,000 | |
Operating Leases, Future Minimum Payments, Due in Four Years | 162,000 | |
Arrangement To Lease Manufacturing and Warehouse Space in a Building Near the Georgia Plant [Member] | ||
Operating Leases, Future Minimum Payments, Remainder of Fiscal Year | 79,000 | |
Operating Leases, Future Minimum Payments, Due in Two Years | 322,000 | |
Operating Leases, Future Minimum Payments, Due in Three Years | 332,000 | |
Operating Leases, Future Minimum Payments, Due in Four Years | $ 342,000 | |
Lessee, Operating Lease, Term of Contract | 5 years 90 days | |
Operating Leases, Future Minimum Payments, Due in Five Years | $ 352,000 | |
Operating Leases, Future Minimum Payments, Due Thereafter | $ 271,000 | |
Otter Tail Power Company [Member] | ||
Number of Utilities Participating in MISO RSG Proceeding Before FERC | 200 | |
Otter Tail Power Company [Member] | Federal Energy Regulatory Commission [Member] | ||
Estimated Liability of Refund Obligation | $ 1,600,000 | |
Otter Tail Power Company [Member] | Coal Purchase Commitments 1 [Member] | ||
Contract Expiration Year | 2,041 | |
Otter Tail Power Company [Member] | Construction Programs [Member] | ||
Contract Expiration Year | 2,019 | 2,019 |
Long-term Purchase Commitment, Amount | $ 45,300,000 | $ 41,000,000 |
Otter Tail Power Company [Member] | Coal Purchase Commitments 2 [Member] | ||
Contract Expiration Year | 2,040 | |
T. O. Plastics, Inc. [Member] | Contract Expiring on December 31, 2021 [Member] | ||
Long-term Purchase Commitment, Amount | $ 5,800,000 | $ 6,700,000 |
Note 9 - Short-term and Long-57
Note 9 - Short-term and Long-term Borrowings (Details Textual) $ in Billions | Feb. 07, 2018USD ($) |
The 2018 Note Purchase Agreement [Member] | |
Debt Instrument, Prepayment, Minimum Percentage of Aggregate Principal Amount | 10.00% |
Debt Instrument, Prepayment, Percentage of the Principal Amount Prepaid | 100.00% |
Debt Instrument, Percentage of Principal Amount to be Offered for Prepayment in the Event of a Change of Control | 100.00% |
Otter Tail Power Company [Member] | Series 2018 A senior Unsecured Notes Due February 7, 2048 [Member] | |
Debt Instrument, Face Amount | $ 0.1 |
Debt Instrument, Interest Rate, Stated Percentage | 4.07% |
Note 9 - Short-term and Long-58
Note 9 - Short-term and Long-term Borrowings - Status of Lines of Credit (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Line Limit | $ 300,000 | |
In Use | 20,977 | |
Restricted due to Outstanding Letters of Credit | 300 | |
Available | 278,723 | $ 187,329 |
Otter Tail Corporation Credit Agreement [Member] | ||
Line Limit | 130,000 | |
In Use | 6,102 | |
Restricted due to Outstanding Letters of Credit | ||
Available | 123,898 | 130,000 |
OTP Credit Agreement [Member] | ||
Line Limit | 170,000 | |
In Use | 14,875 | |
Restricted due to Outstanding Letters of Credit | 300 | |
Available | $ 154,825 | $ 57,329 |
Note 9 - Short-term and Long-59
Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Short-Term Debt | $ 20,977 | $ 112,371 |
Long-Term Debt | 592,604 | 492,711 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 167 | 186 |
Unamortized Long-Term Debt Issuance Costs | 2,477 | 2,145 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 589,960 | 490,380 |
Total Short-Term and Long-Term Debt (with current maturities) | 611,104 | 602,937 |
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | 80,000 | 80,000 |
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Long-Term Debt | ||
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Long-Term Debt | 140,000 | 140,000 |
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Long-Term Debt | 30,000 | 30,000 |
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Long-Term Debt | 42,000 | 42,000 |
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Long-Term Debt | 60,000 | 60,000 |
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Long-Term Debt | 50,000 | 50,000 |
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Long-Term Debt | 90,000 | 90,000 |
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Long-Term Debt | 100,000 | |
North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Long-Term Debt | 27 | |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | 604 | 684 |
Otter Tail Power Company [Member] | ||
Short-Term Debt | 14,875 | 112,371 |
Long-Term Debt | 512,000 | 412,000 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | ||
Unamortized Long-Term Debt Issuance Costs | 2,045 | 1,684 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 509,955 | 410,316 |
Total Short-Term and Long-Term Debt (with current maturities) | 524,830 | 522,687 |
Otter Tail Power Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | ||
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Long-Term Debt | 140,000 | 140,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Long-Term Debt | 30,000 | 30,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Long-Term Debt | 42,000 | 42,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Long-Term Debt | 60,000 | 60,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Long-Term Debt | 50,000 | 50,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Long-Term Debt | 90,000 | 90,000 |
Otter Tail Power Company [Member] | Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Long-Term Debt | 100,000 | |
Otter Tail Power Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | ||
Parent Company [Member] | ||
Short-Term Debt | 6,102 | |
Long-Term Debt | 80,604 | 80,711 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 167 | 186 |
Unamortized Long-Term Debt Issuance Costs | 432 | 461 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 80,005 | 80,064 |
Total Short-Term and Long-Term Debt (with current maturities) | 86,274 | 80,250 |
Parent Company [Member] | The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Long-Term Debt | 80,000 | 80,000 |
Parent Company [Member] | Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Long-Term Debt | ||
Parent Company [Member] | North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Long-Term Debt | 27 | |
Parent Company [Member] | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Long-Term Debt | $ 604 | $ 684 |
Note 9 - Short-term and Long-60
Note 9 - Short-term and Long-term Borrowings - Breakdown of Assignment of Consolidated Short-term and Long-term Debt Outstanding (Details) (Parentheticals) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
The 3.55% Guaranteed Senior Notes, Due December 15, 2026 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.55% | 3.55% |
Long-Term Debt, Due Date | Dec. 15, 2026 | Dec. 15, 2026 |
Term Loan, LIBOR Plus 0.90%, Due February 5, 2018 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 0.90% | |
Long-Term Debt, Due Date | Feb. 5, 2018 | |
Senior Unsecured Notes 4.63%, Due December 1, 2021 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.63% | 4.63% |
Long-Term Debt, Due Date | Dec. 1, 2021 | Dec. 1, 2021 |
Senior Unsecured Notes 6.15%, Series B, Due August 20, 2022 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.15% | 6.15% |
Long-Term Debt, Due Date | Aug. 20, 2022 | Aug. 20, 2022 |
Senior Unsecured Notes 6.37%, Series C, Due August 20, 2027 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.37% | 6.37% |
Long-Term Debt, Due Date | Aug. 20, 2027 | Aug. 20, 2027 |
Senior Unsecured Notes 4.68%, Series A, Due February 27, 2029 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.68% | 4.68% |
Long-Term Debt, Due Date | Feb. 27, 2029 | Feb. 27, 2029 |
Senior Unsecured Notes 6.47%, Series D, Due August 20, 2037 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.47% | 6.47% |
Long-Term Debt, Due Date | Aug. 20, 2037 | Aug. 20, 2037 |
Senior Unsecured Notes 5.47%, Series B, Due February 27, 2044 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.47% | 5.47% |
Long-Term Debt, Due Date | Feb. 27, 2044 | Feb. 27, 2044 |
Senior Unsecured Notes 4.07%, Series 2018A, Due February 7, 2048 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.07% | |
Long-Term Debt, Due Date | Feb. 7, 2048 | |
North Dakota Development Note, 3.95%, Due April 1, 2018 [member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.95% | 3.95% |
Long-Term Debt, Due Date | Apr. 1, 2018 | Apr. 1, 2018 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 [Member] | ||
Debt Instrument, Interest Rate, Stated Percentage | 2.54% | 2.54% |
Long-Term Debt, Due Date | Mar. 18, 2021 | Mar. 18, 2021 |
Note 10 - Pension Plan and Ot61
Note 10 - Pension Plan and Other Postretirement Benefits (Details Textual) - Pension Plan [Member] - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan, Minimum Funding Requirement | $ 0 | |
Defined Benefit Plan, Plan Assets, Contributions by Employer | $ 20,000 |
Note 10 - Pension Plan and Ot62
Note 10 - Pension Plan and Other Postretirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||
Pension Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | $ 1,615 | $ 1,407 | $ 3,230 | $ 2,814 | |
Interest Cost on Projected Benefit Obligation | 3,363 | 3,536 | 6,726 | 7,070 | |
Expected Return on Assets | (5,299) | (4,807) | (10,599) | (9,614) | |
From Regulatory Asset | 4 | 29 | 8 | 59 | |
From Other Comprehensive Income | [1] | 1 | 2 | ||
From Regulatory Asset | 1,783 | 1,272 | 3,567 | 2,545 | |
From Other Comprehensive Income | [1] | 47 | 32 | 91 | 63 |
Net Periodic Pension Cost | [2] | 1,513 | 1,470 | 3,023 | 2,939 |
From Other Comprehensive Income | [1] | 47 | 32 | 91 | 63 |
Pension Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 379 | 286 | 707 | 571 | |
Pension Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 1,195 | 1,100 | 2,442 | 2,200 | |
Pension Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 40 | 34 | 80 | 68 | |
Pension Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | (24) | (45) | |||
Pension Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | (77) | 50 | (161) | 100 | |
Executive Survivor and Supplemental Retirement Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 100 | 72 | 200 | 145 | |
Interest Cost on Projected Benefit Obligation | 399 | 421 | 798 | 843 | |
From Regulatory Asset | 4 | 4 | 8 | 8 | |
From Other Comprehensive Income | [3] | 9 | 10 | 19 | 19 |
From Regulatory Asset | 67 | 72 | 134 | 143 | |
From Other Comprehensive Income | [3] | 165 | 110 | 330 | 220 |
Net Periodic Pension Cost | [4] | 744 | 689 | 1,489 | 1,378 |
From Other Comprehensive Income | [3] | 165 | 110 | 330 | 220 |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 25 | 23 | 50 | 47 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 75 | 49 | 150 | 98 | |
Executive Survivor and Supplemental Retirement Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | 644 | 617 | 1,289 | 1,233 | |
Other Postretirement Benefits Plan [Member] | |||||
Service Cost—Benefit Earned During the Period | 381 | 356 | 763 | 712 | |
Interest Cost on Projected Benefit Obligation | 646 | 678 | 1,291 | 1,356 | |
From Regulatory Asset | 412 | 233 | 824 | 466 | |
From Other Comprehensive Income | [1] | 11 | 6 | 21 | 12 |
Net Periodic Pension Cost | [5] | 1,450 | 1,273 | 2,899 | 2,546 |
Effect of Medicare Part D Subsidy | (36) | (140) | (73) | (280) | |
Other Postretirement Benefits Plan [Member] | Costs Included in OTP Capital Expenditures [Member] | |||||
Net Periodic Pension Cost | 89 | 248 | 167 | 495 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Electric Operation and Maintenance Expenses [Member] | |||||
Net Periodic Pension Cost | 283 | 279 | 577 | 557 | |
Other Postretirement Benefits Plan [Member] | Costs Included in Other Nonelectric Expenses [Member] | |||||
Net Periodic Pension Cost | 9 | 8 | 19 | 17 | |
Other Postretirement Benefits Plan [Member] | Nonservice Costs Capitalized as Regulatory Assets [Member] | |||||
Net Periodic Pension Cost | 251 | 468 | |||
Other Postretirement Benefits Plan [Member] | Nonservice Costs Included in Nonservice Cost Components of Postretirement Benefits [Member] | |||||
Net Periodic Pension Cost | $ 818 | $ 738 | $ 1,668 | $ 1,477 | |
[1] | Corporate cost included in nonservice cost components of postretirement benefits. | ||||
[2] | Allocation of Costs: Costs included in OTP capital expenditures $ 379 $ 286 $ 707 $ 571 Service costs included in electric operation and maintenance expenses 1,195 1,100 2,442 2,200 Service costs included in other nonelectric expenses 40 34 80 68 Nonservice costs capitalized as regulatory assets (24 ) -- (45 ) -- Nonservice costs included in nonservice cost components of postretirement benefits (77 ) 50 (161 ) 100 | ||||
[3] | Amortization of prior service costs and net actuarial losses from other comprehensive income are included in nonservice cost components of postretirement benefits on the face of the Company's consolidated statements of income. | ||||
[4] | Allocation of Costs: Service costs included in electric operation and maintenance expenses $ 25 $ 23 $ 50 $ 47 Service costs included in other nonelectric expenses 75 49 150 98 Nonservice costs included in nonservice cost components of postretirement benefits 644 617 1,289 1,233 | ||||
[5] | Allocation of Costs: Costs included in OTP capital expenditures $ 89 $ 248 $ 167 $ 495 Service costs included in electric operation and maintenance expenses 283 279 577 557 Service costs included in other nonelectric expenses 9 8 19 17 Nonservice costs capitalized as regulatory assets 251 -- 468 -- Nonservice costs included in nonservice cost components of postretirement benefits 818 738 1,668 1,477 |
Note 11 - Fair Value of Finan63
Note 11 - Fair Value of Financial Instruments (Details Textual) - London Interbank Offered Rate (LIBOR) [Member] | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Otter Tail Corporation Credit Agreement [Member] | ||
Debt Instrument, Basis Spread on Variable Rate | 1.50% | 1.50% |
Debt Instrument, Description of Variable Rate Basis | LIBOR | LIBOR |
OTP Credit Agreement [Member] | ||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | 1.25% |
Debt Instrument, Description of Variable Rate Basis | LIBOR | LIBOR |
Note 11 - Fair Value of Finan64
Note 11 - Fair Value of Financial Instruments - Summary of Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Reported Value Measurement [Member] | ||
Cash and Cash Equivalents | $ 1,036 | $ 16,216 |
Short-Term Debt | (20,977) | (112,371) |
Long-Term Debt including Current Maturities | (590,127) | (490,566) |
Estimate of Fair Value Measurement [Member] | ||
Cash and Cash Equivalents | 1,036 | 16,216 |
Short-Term Debt | (20,977) | (112,371) |
Long-Term Debt including Current Maturities | $ (605,185) | $ (543,691) |
Note 13 - Income Tax Expense 65
Note 13 - Income Tax Expense - Continuing Operations (Details Textual) $ in Thousands | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Period for Unrecognized Tax Benefits Not Expected Change | 1 year |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | $ 0 |
Note 13 - Income Tax Expense 66
Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income Before Income Taxes – Continuing Operations | $ 21,750 | $ 22,614 | $ 51,759 | $ 48,506 |
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (26% for 2018, 39% for 2017) | 5,655 | 8,819 | 13,457 | 18,917 |
Increases (Decreases) in Tax from: | ||||
Property Related Differences and Other Regulatory Adjustments | (1,025) | 35 | (2,098) | 140 |
Federal Production Tax Credits | (930) | (2,010) | (2,050) | (4,062) |
Excess Tax Deduction – Equity Method Stock Awards | (624) | (697) | ||
Other Comprehensive Income Deferred Tax Rate Adjustment | (531) | |||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (258) | (213) | (516) | (425) |
Research and Development and Other Tax Credits | (202) | (190) | (409) | (387) |
Allowance for Funds Used During Construction – Equity | (111) | (91) | (278) | (158) |
Employee Stock Ownership Plan Dividend Deduction | (99) | (172) | (199) | (345) |
Section 199 Domestic Production Activities Deduction | (330) | (660) | ||
Other Items – Net | 24 | 49 | 96 | (63) |
Income Tax Expense – Continuing Operations | $ 3,054 | $ 5,897 | $ 6,848 | $ 12,260 |
Effective Income Tax Rate – Continuing Operations | 14.00% | 26.10% | 13.20% | 25.30% |
Note 13 - Income Tax Expense 67
Note 13 - Income Tax Expense - Continuing Operations - Effective Income Tax Rate (Details) (Parentheticals) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Composite Federal and State Statutory Rate | 26.00% | 39.00% | 26.00% | 39.00% |
Note 13 - Income Tax Expense 68
Note 13 - Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax Benefit (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Balance, beginning | $ 684 | $ 891 |
Decreases Related to Tax Positions for Prior Years | (44) | |
Increases Related to Tax Positions for Current Year | 72 | 147 |
Uncertain Positions Resolved During Year | ||
Balance, ending | $ 712 | $ 1,038 |