Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | Apr. 30, 2017 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Otter Tail Corp | |
Entity Central Index Key | 1,466,593 | |
Trading Symbol | ottr | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock Shares Outstanding | 39,503,539 | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2017 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 |
Consolidated Balance Sheets (no
Consolidated Balance Sheets (not audited) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and Cash Equivalents | ||
Accounts Receivable: | ||
Trade - Net | 82,369 | 68,242 |
Other | 7,244 | 5,850 |
Inventories | 81,473 | 83,740 |
Unbilled Revenues | 18,016 | 20,080 |
Income Taxes Receivable | 662 | |
Regulatory Assets | 17,973 | 21,297 |
Other | 11,837 | 8,144 |
Total Current Assets | 218,912 | 208,015 |
Investments | 8,125 | 8,417 |
Other Assets | 35,416 | 34,104 |
Goodwill | 37,572 | 37,572 |
Other Intangibles - Net | 14,626 | 14,958 |
Regulatory Assets | 128,968 | 132,094 |
Plant | ||
Electric Plant in Service | 1,868,689 | 1,860,357 |
Nonelectric Operations | 212,976 | 211,826 |
Construction Work in Progress | 166,866 | 153,261 |
Total Gross Plant | 2,248,531 | 2,225,444 |
Less Accumulated Depreciation and Amortization | 761,444 | 748,219 |
Net Plant | 1,487,087 | 1,477,225 |
Total Assets | 1,930,706 | 1,912,385 |
Current Liabilities | ||
Short-Term Debt | 59,176 | 42,883 |
Current Maturities of Long-Term Debt | 45,192 | 33,201 |
Accounts Payable | 83,622 | 89,350 |
Accrued Salaries and Wages | 12,957 | 17,497 |
Accrued Federal and State Income Taxes | 1,107 | |
Other Accrued Taxes | 17,068 | 16,000 |
Other Accrued Liabilities | 15,584 | 15,377 |
Liabilities of Discontinued Operations | 1,268 | 1,363 |
Total Current Liabilities | 235,974 | 215,671 |
Pensions Benefit Liability | 97,962 | 97,627 |
Other Postretirement Benefits Liability | 62,796 | 62,571 |
Other Noncurrent Liabilities | 22,168 | 21,706 |
Commitments and Contingencies (note 9) | ||
Deferred Credits | ||
Deferred Income Taxes | 231,210 | 226,591 |
Deferred Tax Credits | 22,483 | 22,849 |
Regulatory Liabilities | 82,316 | 82,433 |
Other | 6,302 | 7,492 |
Total Deferred Credits | 342,311 | 339,365 |
Capitalization | ||
Long-Term Debt - Net | 490,372 | 505,341 |
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2017 - 39,468,804 Shares; 2016 - 39,348,136 Shares | 197,344 | 196,741 |
Premium on Common Shares | 339,036 | 337,684 |
Retained Earnings | 146,438 | 139,479 |
Accumulated Other Comprehensive Loss | (3,695) | (3,800) |
Total Common Equity | 679,123 | 670,104 |
Total Capitalization | 1,169,495 | 1,175,445 |
Total Liabilities and Equity | 1,930,706 | 1,912,385 |
Cumulative Preferred Shares | ||
Capitalization | ||
Cumulative Shares | ||
Cumulative Preference Shares | ||
Capitalization | ||
Cumulative Shares |
Consolidated Balance Sheets (n3
Consolidated Balance Sheets (not audited) (Parentheticals) - $ / shares | Mar. 31, 2017 | Dec. 31, 2016 |
Common shares, par value (in dollars per share) | $ 5 | $ 5 |
Common shares, authorized | 50,000,000 | 50,000,000 |
Common shares, outstanding | 39,468,804 | 39,348,136 |
Cumulative Preferred Shares | ||
Cumulative shares, authorized | 1,500,000 | 1,500,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding | 0 | 0 |
Cumulative Preference Shares | ||
Cumulative shares, authorized | 1,000,000 | 1,000,000 |
Cumulative shares, without par value (in dollars per share) | $ 0 | $ 0 |
Cumulative shares, outstanding | 0 | 0 |
Consolidated Statements of Inco
Consolidated Statements of Income (not audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Operating Revenues | ||
Electric | $ 118,543 | $ 112,985 |
Product Sales | 95,574 | 93,257 |
Total Operating Revenues | 214,117 | 206,242 |
Operating Expenses | ||
Production Fuel - Electric | 16,382 | 15,700 |
Purchased Power - Electric | 19,188 | 16,886 |
Electric Operation and Maintenance Expenses | 38,379 | 40,018 |
Cost of Products Sold (depreciation included below) | 75,277 | 72,639 |
Other Nonelectric Expenses | 10,438 | 11,455 |
Depreciation and Amortization | 17,854 | 18,289 |
Property Taxes - Electric | 3,798 | 3,679 |
Total Operating Expenses | 181,316 | 178,666 |
Operating Income | 32,801 | 27,576 |
Interest Charges | 7,462 | 7,994 |
Other Income | 553 | 400 |
Income Before Income Taxes - Continuing Operations | 25,892 | 19,982 |
Income Tax Expense - Continuing Operations | 6,363 | 5,492 |
Net Income from Continuing Operations | 19,529 | 14,490 |
Income from Discontinued Operations - net of Income Tax Expense of $38 in 2017 and $20 in 2016 | 56 | 30 |
Net Income | $ 19,585 | $ 14,520 |
Average Number of Common Shares Outstanding - Basic | 39,350,802 | 37,936,943 |
Average Number of Common Shares Outstanding - Diluted | 39,640,725 | 38,045,208 |
Basic Earnings Per Common Share: | ||
Continuing Operations (in dollars per share) | $ 0.50 | $ 0.38 |
Discontinued Operations (in dollars per share) | ||
Earnings Per Share, Basic, Total (in dollars per share) | 0.50 | 0.38 |
Diluted Earnings Per Common Share: | ||
Continuing Operations (in dollars per share) | 0.49 | 0.38 |
Discontinued Operations (in dollars per share) | ||
Earnings Per Share, Diluted, Total (in dollars per share) | 0.49 | 0.38 |
Dividends Declared Per Common Share (in dollars per share) | $ 0.3200 | $ 0.3125 |
Consolidated Statements of Inc5
Consolidated Statements of Income (not audited) (Parentheticals) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Statement [Abstract] | ||
Income tax expense (benefit) on income (loss) from discontinued operation | $ 38 | $ 20 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (not audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Statement Of Income and Comprehensive Income [Abstract] | ||
Net Income | $ 19,585 | $ 14,520 |
Unrealized Gains on Available-for-Sale Securities: | ||
Gains Arising During Period | 17 | 73 |
Income Tax Expense | (6) | (26) |
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax | 11 | 47 |
Pension and Postretirement Benefit Plans: | ||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 157 | 154 |
Income Tax Expense | (63) | (61) |
Pension and Postretirement Benefit Plans - net-of-tax | 94 | 93 |
Total Other Comprehensive Income | 105 | 140 |
Total Comprehensive Income | $ 19,690 | $ 14,660 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (not audited) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash Flows from Operating Activities | ||
Net Income | $ 19,585 | $ 14,520 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||
Net Income from Discontinued Operations | (56) | (30) |
Depreciation and Amortization | 17,854 | 18,289 |
Deferred Tax Credits | (366) | (414) |
Deferred Income Taxes | 4,512 | 5,330 |
Change in Deferred Debits and Other Assets | 5,005 | 2,825 |
Discretionary Contribution to Pension Plan | (10,000) | |
Change in Noncurrent Liabilities and Deferred Credits | 1,314 | 3,363 |
Allowance for Equity/Other Funds Used During Construction | (170) | (95) |
Stock Compensation Expense - Equity Awards | 1,150 | 489 |
Other - Net | (5) | 15 |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | (15,521) | (7,478) |
Change in Inventories | 2,267 | 6 |
Change in Other Current Assets | (22) | (773) |
Change in Payables and Other Current Liabilities | (13,986) | (5,840) |
Change in Interest and Income Taxes Receivable/Payable | (321) | 2,400 |
Net Cash Provided by Continuing Operations | 21,240 | 22,607 |
Net Cash (Used in) Provided by Discontinued Operations | (39) | 30 |
Net Cash Provided by Operating Activities | 21,201 | 22,637 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (30,113) | (24,855) |
Net Proceeds from Disposal of Noncurrent Assets | 612 | 682 |
Cash Used for Investments and Other Assets | (508) | (1,425) |
Net Cash Used in Investing Activities | (30,009) | (25,598) |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | 7,999 | (666) |
Net Short-Term Borrowings (Repayments) | 16,293 | (37,736) |
Proceeds from Issuance of Common Stock - net of Issuance Expenses | 1,958 | 3,415 |
Payments for Retirement of Capital Stock | (1,759) | (53) |
Proceeds from Issuance of Long-Term Debt | 50,000 | |
Short-Term and Long-Term Debt Issuance Expenses | (58) | |
Payments for Retirement of Long-Term Debt | (3,057) | (52) |
Dividends Paid | (12,626) | (11,889) |
Net Cash Provided by Financing Activities | 8,808 | 2,961 |
Net Change in Cash and Cash Equivalents | ||
Cash and Cash Equivalents at Beginning of Period | ||
Cash and Cash Equivalents at End of Period |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 1. Summary of Significant Accounting Policies Revenue Recognition Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized. For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. Agreements Subject to Legally Enforceable Netting Arrangements The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. Fair Value Measurements The Company follows Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX). Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016: March 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,590 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,345 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 828 Total Assets $ 828 $ 7,935 December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company Coyote Station Lignite Supply Agreement – Variable Interest Entity If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2017 could be as high as $59.7 million, OTP’s 35% share of unrecovered costs. Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2017 2016 Finished Goods $ 24,018 $ 27,755 Work in Process 12,801 11,754 Raw Material, Fuel and Supplies 44,654 44,231 Total Inventories $ 81,473 $ 83,740 Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2016 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table indicates there were no changes to goodwill by business segment during the first three months of 2017: (in thousands) Gross Balance Accumulated Balance Adjustments to Balance Manufacturing $ 18,270 $ — $ 18,270 $ — $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 37,572 $ — $ 37,572 $ — $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2017 and December 31, 2016: March 31, 2017 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,144 $ 14,347 33-221 months Covenant not to Compete 590 311 279 17 months Total $ 23,081 $ 8,455 $ 14,626 December 31, 2016 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2017 2016 Amortization Expense – Intangible Assets $ 332 $ 357 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099 Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2017 2016 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,811 $ 24,618 New Accounting Standards Adopted Accounting Standards Update (ASU) 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, New Accounting Standards Pending Adoption ASU 2014-09 Revenue from Contracts with Customers (Topic 606) Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of March 31, 2017 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09. The treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. The Company does not plan to adopt the updated guidance prior to January 1, 2018. ASU 2016-02 Leases (Topic 842) ASU 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. Topic 715, Compensation—Retirement Benefits , The majority of the Company’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU 2017-07 may have on its consolidated financial statements, financial position and results of operations and is determining what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated income statements upon adoption of the amendments in ASU 2017-07. The Company does not plan to adopt the updates in ASU 2017-07 prior to the first quarter of 2018, the required effective period for application of the updates by the Company. |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Information | 2. Segment Information Segment Information The accounting policies of the segments are described under note 1 – Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers. Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP’s operations have been the Company’s primary business since 1907. Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States. Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States. OTP is a wholly owned subsidiary of the Company. All of the Company’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements. No single customer accounted for over 10% of the Company’s consolidated revenues in 2016. All of the Company’s long-lived assets are within the United States and 98.4% and 97.6% of its operating revenues for the respective three month periods ended March 31, 2017 and 2016 came from sales within the United States. 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 months ended March 31, 2017 and 2016 and total assets by business segment as of March 31, 2017 and December 31, 2016 are presented in the following tables: Operating Revenue Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 118,551 $ 112,994 Manufacturing 58,417 59,820 Plastics 37,157 33,437 Intersegment Eliminations (8 ) (9 ) Total $ 214,117 $ 206,242 Interest Charges Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 6,386 $ 6,284 Manufacturing 554 992 Plastics 153 244 Corporate and Intersegment Eliminations 369 474 Total $ 7,462 $ 7,994 Income Taxes Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 6,062 $ 4,612 Manufacturing 1,055 1,019 Plastics 1,390 1,367 Corporate (2,144 ) (1,506 ) Total $ 6,363 $ 5,492 Net Income (Loss) Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 15,560 $ 12,538 Manufacturing 2,172 1,853 Plastics 2,437 2,152 Corporate (640 ) (2,053 ) Discontinued Operations 56 30 Total $ 19,585 $ 14,520 Identifiable Assets March 31, December 31, (in thousands) 2017 2016 Electric $ 1,630,071 $ 1,622,231 Manufacturing 170,805 166,525 Plastics 91,049 84,592 Corporate 38,781 39,037 Total $ 1,930,706 $ 1,912,385 |
Rate and Regulatory Matters
Rate and Regulatory Matters | 3 Months Ended |
Mar. 31, 2017 | |
Rate and Regulatory Matters [Abstract] | |
Rate and Regulatory Matters | 3. Rate and Regulatory Matters Below are descriptions of OTP’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC), impacting OTP’s revenues in 2017 and 2016. Major Capital Expenditure Projects The Big Stone South – Brookings Multi-Value Transmission Project (MVP) and Capacity Expansion 2020 (CapX2020) Project MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. The Big Stone South – Ellendale MVP Recovery of OTP’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. Minnesota 2016 General Rate Case ($ in thousands) Annualized or Actual Through Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 15,335 The deadline for submission of intervenor direct testimony was August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54% allowed rate of return on equity. Oral arguments before the MPUC occurred February 23, 2017 with deliberations on March 2, 2017. The MPUC rendered its final decision in March 2017 and issued its written order on May 1, 2017. The MPUC authorized a revenue increase of approximately $12.3 million through a 6.27% increase in base rate revenues compared to the authorized interim rate increase of 9.56%. The MPUC’s written order included: (1) an allowed rate of return on equity of 9.41%, (2) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South to Brookings and Big Stone South to Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (3) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (ECR) and TCR riders to base rate recovery, with the transition occurring at the time final rates are implemented at the end of this rate case. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs. Pursuant to the order, OTP’s allowed rate of return on rate base will decrease from 8.61% to 7.5056% and its allowed rate of return on equity will decrease from 10.74% to 9.41%. OTP's rate of return will be based on a capital structure of 47.50% long term debt and 52.50% common equity. Parties may request clarification or reconsideration of the MPUC’s rulings consistent with Minnesota law. Based on the MPUC deliberations regarding OTP’s 2016 revenue increase request, OTP had recorded an estimated interim rate refund of $5.2 million, including interest, as of March 31, 2017. 2010 General Rate Case Minnesota Conservation Improvement Programs (MNCIP) Transmission Cost Recovery Rider Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. In OTP’s 2016 general rate case, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s share of 100% of OTP’s investment in the Big Stone South – Brookings and Big Stone South – Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations, despite an ALJ recommendation that the MPUC affirm OTP’s proposed treatment. The MPUC ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Environmental Cost Recovery Rider North Dakota General Rates Renewable Resource Adjustment Transmission Cost Recovery Rider Environmental Cost Recovery Rider OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. The ECR rider provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case. South Dakota 2010 General Rate Case Transmission Cost Recovery Rider Environmental Cost Recovery Rider Rate Rider Updates The following table provides summary information on the status of updates for the previous two years for the various rate riders described above: Rate Rider R - Request Date Effective Date Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2016 Incentive and Cost Recovery R – March 31, 2017 October 1, 2017 $ 9,868 $0.00754/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh 2014 Incentive and Cost Recovery A – July 10, 2015 October 1, 2015 $ 8,689 $0.00287/kwh Transmission Cost Recovery 2016 Annual Update 1 A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various 2014 Annual Update A – February 18, 2015 March 1, 2015 $ 8,388 Various Environmental Cost Recovery 2016 Annual Update 1 A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of Rev 2015 Annual Update A – March 9, 2016 October 1, 2015 $ 12,104 7.006% of Rev North Dakota Renewable Resource Adjustment 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of Rev 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of Rev 2014 Annual Update A – March 25, 2015 April 1, 2015 $ 5,441 4.069% of Rev Transmission Cost Recovery 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various 2015 Annual Update A – December 16, 2015 January 1, 2016 $ 9,985 Various Environmental Cost Recovery 2017 Annual Update R – March 31, 2017 July 1 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base 2015 Annual Update A – June 17, 2015 July 1, 2015 $ 12,249 9.193% of base South Dakota Transmission Cost Recovery 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 2014 Annual Update A – February 13, 2015 March 1, 2015 $ 1,538 Various Environmental Cost Recovery 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 2015 Annual Update A – October 15, 2015 November 1, 2015 $ 2,728 $0.00643/kwh 1 Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31: Rate Rider (in thousands) 2017 2016 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 1,966 $ 2,506 Transmission Cost Recovery 2,170 2,276 Environmental Cost Recovery 2,824 3,082 North Dakota Renewable Resource Adjustment 1,770 2,059 Transmission Cost Recovery 2,511 2,236 Environmental Cost Recovery 2,488 2,811 South Dakota Transmission Cost Recovery 441 651 Environmental Cost Recovery 597 633 Conservation Improvement Program Costs and Incentives 240 159 1 FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935, as amended. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC. Multi-Value Transmission Projects—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit. On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding ALJ was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016. On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. A lack of a quorum at FERC will delay the issuance of an order in the second complaint for an uncertain period of time. Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for 90% of the FERC ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period in its February 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.7 million as of March 31, 2017. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 3 Months Ended |
Mar. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | 4. Regulatory Assets and Liabilities As a regulated entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980, Regulated Operations March 31, 2017 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,443 $ 106,656 $ 113,099 see below Deferred Marked-to-Market Losses 1 4,063 5,452 9,515 45 months Conservation Improvement Program Costs and Incentives 2 3,745 5,735 9,480 30 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,276 6,276 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 739 1,926 2,665 49 months Debt Reacquisition Premiums 1 301 1,150 1,451 186 months Deferred Income Taxes 1 — 1,020 1,020 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 954 — 954 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 727 62 789 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 517 617 74 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 426 59 485 21 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 251 115 366 21 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 106 — 106 11 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 95 — 95 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 23 — 23 6 months Total Regulatory Assets $ 17,973 $ 128,968 $ 146,941 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 81,314 $ 81,314 asset lives Refundable Fuel Clause Adjustment Revenues 2,119 — 2,119 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 1,545 — 1,545 12 months Deferred Income Taxes — 785 785 asset lives Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 30 741 13 months Minnesota Environmental Cost Recovery Rider Accrued Refund 631 — 631 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 354 — 354 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 299 — 299 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 33 99 132 21 months South Dakota Transmission Cost Recovery Rider Accrued Refund 8 — 8 12 months Other 6 88 94 201 months Total Regulatory Liabilities $ 5,706 $ 82,316 $ 88,022 Net Regulatory Asset Position $ 12,267 $ 46,652 $ 58,919 1 2 December 31, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,443 $ 108,267 $ 114,710 see below Deferred Marked-to-Market Losses 1 4,063 6,467 10,530 48 months Conservation Improvement Program Costs and Incentives 2 4,836 5,158 9,994 21 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,153 6,153 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 778 2,087 2,865 52 months Recoverable Fuel and Purchased Power Costs 1 1,798 — 1,798 12 months Debt Reacquisition Premiums 1 325 1,214 1,539 189 months Deferred Income Taxes 1 — 1,014 1,014 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 1,082 — 1,082 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,319 482 1,801 15 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 543 643 77 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 568 568 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 333 — 333 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 73 141 214 14 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 113 — 113 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 34 — 34 9 months Total Regulatory Assets $ 21,297 $ 132,094 $ 153,391 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 80,404 $ 80,404 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 1,381 782 2,163 24 months Deferred Income Taxes — 818 818 asset lives Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 208 919 16 months Minnesota Transmission Cost Recovery Rider Accrued Refund 757 — 757 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 139 — 139 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 285 — 285 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 132 132 24 months Other 21 89 110 204 months Total Regulatory Liabilities $ 3,294 $ 82,433 $ 85,727 Net Regulatory Asset Position $ 18,003 $ 49,661 $ 67,664 1 2 The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits All Deferred Marked-to-Market Losses recorded as of March 31, 2017 relate to forward purchases of energy scheduled for delivery through December 2020. Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates. The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations. Big Stone II Unrecovered Project Costs – Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 186 months. The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740, Income Taxes Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016. North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of March 31, 2017. Big Stone II Unrecovered Project Costs – South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project. The North Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of March 31, 2017. MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule. The South Dakota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of March 31, 2017. The Minnesota Transmission Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March 31, 2017. Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016. The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2017. Revenue for Rate Case Expenses Subject to Refund – Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016. The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to Minnesota customers as of March 31, 2017. The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of March 31, 2017. The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of March 31, 2017. The South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of March 31, 2017. If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases. |
Open Contract Positions Subject
Open Contract Positions Subject to Legally Enforceable Netting Arrangements | 3 Months Ended |
Mar. 31, 2017 | |
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract] | |
Open Contract Positions Subject to Legally Enforceable Netting Arrangements | 5. Open Contract Positions Subject to Legally Enforceable Netting Arrangements OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of March 31, 2017 and December 31, 2016: (in thousands) March 31, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (14,590 ) (17,382 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (14,590 ) $ (17,382 ) The following table provides a breakdown of OTP’s credit risk standing on forward energy contracts in marked-to-market loss positions as of March 31, 2017 and December 31, 2016: (in thousands) March 31, December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ — $ — Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,590 17,382 Total Loss Contracts based on Current Market Values $ 14,590 $ 17,382 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,590 $ 17,382 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 14,590 $ 17,382 |
Reconciliation of Common Shareh
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 3 Months Ended |
Mar. 31, 2017 | |
Stockholders Equity and Earnings Per Share [Abstract] | |
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 6. Reconciliation of Common Shareholders’ Equity, Common Shares and Earnings Per Share Reconciliation of Common Shareholders’ Equity (in thousands) Par Value, Premium Retained Accumulated Total Balance, December 31, 2016 $ 196,741 $ 337,684 $ 139,479 $ (3,800 ) $ 670,104 Common Stock Issuances, Net of Expenses 837 1,727 2,564 Common Stock Retirements (234 ) (1,525 ) (1,759 ) Net Income 19,585 19,585 Other Comprehensive Income 105 105 Employee Stock Incentive Plans Expense 1,150 1,150 Common Dividends ($0.32 per share) (12,626 ) (12,626 ) Balance, March 31, 2017 $ 197,344 $ 339,036 $ 146,438 $ (3,695 ) $ 679,123 Shelf Registration and Common Share Distribution Agreement The Company’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018. On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million. Common Shares Following is a reconciliation of the Company’s common shares outstanding from December 31, 2016 through March 31, 2017: Common Shares Outstanding, December 31, 2016 39,348,136 Issuances: Executive Stock Performance Awards (2014 shares earned) 89,291 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 36,320 Cash Invested 11,750 Employee Stock Ownership Plan 14,835 Vesting of Restricted Stock Units 9,975 Employee Stock Purchase Plan: Cash Invested — Dividends Reinvested 5,131 Retirements: Shares Withheld for Individual Income Tax Requirements (46,634 ) Common Shares Outstanding, March 31, 2017 39,468,804 Earnings Per Share The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three month periods ended March 31, 2017 and 2016. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation for the three month periods ended March 31: 2017 2016 Weighted Average Common Shares Outstanding – Basic 39,350,802 37,936,943 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 201,639 46,885 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,873 39,841 Nonvested Restricted Shares 27,069 17,776 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,342 3,763 Total Dilutive Shares 289,923 108,265 Weighted Average Common Shares Outstanding – Diluted 39,640,725 38,045,208 The effect of dilutive shares on earnings per share for the three month periods ended March 31, 2017 and 2016, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period. |
Share-Based Payments
Share-Based Payments | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | |
Share-Based Payments | 7. Share-Based Payments Stock Incentive Awards On February 2, 2017 the following stock incentive awards were granted to officers under the 2014 Incentive Plan: Award Shares/Units Weighted Vesting Restricted Stock Units Granted 15,900 $ 37.65 25% per year through February 6, 2021 Stock Performance Awards Granted 59,500 $ 31.00 December 31, 2019 The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit was the average of the high and low market price per share on the date of grant. Under the performance share awards, the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted return on equity. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are no voting or dividend rights related to the performance shares until common shares, if any, are issued at the end of the performance measurement period. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of the award. Under the 2017 Performance Award Agreements, payment and the amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event. The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement. As of March 31, 2017 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $5.3 million (before income taxes) which will be amortized over a weighted-average period of 2.3 years. Amounts of compensation expense recognized under the Company’s six stock-based payment programs for the three month periods ended March 31, 2017 and 2016 are presented in the table below: Three months ended March 31, (in thousands) 2017 2016 Stock Performance Awards Granted to Executive Officers $ 649 $ 537 Restricted Stock Units Granted to Executive Officers 264 245 Restricted Stock Granted to Executive Officers 22 29 Restricted Stock Granted to Directors 128 107 Restricted Stock Units Granted to Non-Executive Employees 87 64 Employee Stock Purchase Plan (15% discount) — 44 Totals $ 1,150 $ 1,026 |
Retained Earnings Restriction
Retained Earnings Restriction | 3 Months Ended |
Mar. 31, 2017 | |
Retained Earnings Restrictions [Abstract] | |
Retained Earnings Restriction | 8. Retained Earnings Restriction The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries. Both the Company and OTP debt agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of March 31, 2017 the Company was in compliance with these financial covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2016 for further information on the covenants. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity-to-total-capitalization ratio between 47.5% and 58.1% based on OTP’s 2016 capital structure petition approved by order of the MPUC on August 2, 2016. As of March 31, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $443,000,000. Total capitalization for OTP cannot currently exceed $1,123,168,000. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 9. Commitments and Contingencies Construction and Other Purchase Commitments At December 31, 2016 OTP had commitments under contracts, including its share of construction program commitments extending into 2019, of approximately $84.8 million. At March 31, 2017 OTP had commitments under contracts, including its share of construction program commitments, extending into 2019, of approximately $114.6 million. Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of 2019 and 2040, respectively. In the first quarter of 2017 OTP rolled forward a portion of its coal supply for Big Stone Plant that it expected to take delivery of in 2016 into 2018 and entered into an agreement to purchase additional tons in 2019. These arrangements result in an additional commitment for the purchase of coal in 2018 and 2019 totaling approximately $3.0 million. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant for the period of January 1, 2016 through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement. Operating Leases OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment. Contingencies OTP had a $2.7 million refund liability on its balance sheet as of December 31, 2016 representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. In the February 2017 MISO billings MISO processed the refund of 90% of the FERC-ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million as of December 31, 2016 to $1.7 million as of March 31, 2017. Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders and the FERC’s decision to resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. These consolidated cases are currently held in abeyance while the parties engage in mediation before the D.C. Circuit. The parties have been unable to settle the issues on appeal and the cases will likely revert to the active calendar of the D.C. Circuit. The scope of the issues that will be subject to appeal at the D.C. Circuit have not yet been finalized. In addition, MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders. Although the Company cannot estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse effect on the Company’s results of operations. Contingencies, by their nature, relate to uncertainties that require the Company’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time. In 2014 the Environmental Protection Agency (EPA) published proposed standards of performance for carbon dioxide (CO 2 2 Promoting Energy Independence and Economic Growth 2 2 Other The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2017 will not be material. |
Short-Term and Long-Term Borrow
Short-Term and Long-Term Borrowings | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Short-Term and Long-Term Borrowings | 10. Short-Term and Long-Term Borrowings The following table presents the status of our lines of credit as of March 31, 2017 and December 31, 2016: (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 130,000 $ 12,825 $ — $ 117,175 $ 130,000 OTP Credit Agreement 170,000 46,351 50 123,599 127,067 Total $ 300,000 $ 59,176 $ 50 $ 240,774 $ 257,067 Debt Retirements On February 5, 2016 the Company borrowed $50 million under a Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points. The Company repaid $35.0 million of the $50 million in the fourth quarter of 2016 and repaid an additional $3.0 million in the first quarter of 2017. The following tables provide a breakdown of the assignment of the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2017 and December 31, 2016: March 31, 2017 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 46,351 $ 12,825 $ 59,176 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 12,000 $ 12,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 86 86 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 799 799 Total $ 445,000 $ 92,885 $ 537,885 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,981 12,211 45,192 Unamortized Long-Term Debt Issuance Costs 1,801 520 2,321 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,218 $ 80,154 $ 490,372 Total Short-Term and Long-Term Debt (with current maturities) $ 489,550 $ 105,190 $ 594,740 December 31, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 42,883 $ — $ 42,883 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 15,000 $ 15,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 106 106 PACE Note, 2.54%, due March 18, 2021 836 836 Total $ 445,000 $ 95,942 $ 540,942 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,970 231 33,201 Unamortized Long-Term Debt Issuance Costs 1,861 539 2,400 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,169 $ 95,172 $ 505,341 Total Short-Term and Long-Term Debt (with current maturities) $ 486,022 $ 95,403 $ 581,425 |
Pension Plan and Other Postreti
Pension Plan and Other Postretirement Benefits | 3 Months Ended |
Mar. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Pension Plan and Other Postretirement Benefits | 11. Pension Plan and Other Postretirement Benefits Pension Plan Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 1,407 $ 1,382 Interest Cost on Projected Benefit Obligation 3,534 3,522 Expected Return on Assets (4,807 ) (4,867 ) Amortization of Prior-Service Cost: From Regulatory Asset 30 47 From Other Comprehensive Income 1 1 1 Amortization of Net Actuarial Loss: From Regulatory Asset 1,273 1,227 From Other Comprehensive Income 1 31 31 Net Periodic Pension Cost $ 1,469 $ 1,343 1 Cash flows Executive Survivor and Supplemental Retirement Plan Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 73 $ 63 Interest Cost on Projected Benefit Obligation 422 417 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 From Other Comprehensive Income 1 9 9 Amortization of Net Actuarial Loss: From Regulatory Asset 71 73 From Other Comprehensive Income 2 110 112 Net Periodic Pension Cost $ 689 $ 678 1 Electric Operation and Maintenance Expenses $ 4 $ 4 Other Nonelectric Expenses 5 5 2 Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44 Postretirement Benefits Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 356 $ 306 Interest Cost on Projected Benefit Obligation 678 541 Amortization of Prior-Service Costs: From Regulatory Asset — 33 From Other Comprehensive Income 1 — 1 Amortization of Net Actuarial Loss: From Regulatory Asset 233 — From Other Comprehensive Income 1 6 — Net Periodic Postretirement Benefit Cost $ 1,273 $ 881 Effect of Medicare Part D Subsidy $ (140 ) $ (257 ) 1 Corporate cost included in Other Nonelectric Expenses. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | 12. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: Short-Term Debt Long-Term Debt including Current Maturities March 31, 2017 December 31, 2016 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (59,176 ) (59,176 ) (42,883 ) (42,883 ) Long-Term Debt including Current Maturities (535,564 ) (582,743 ) (538,542 ) (583,835 ) |
Income Tax Expense - Continuing
Income Tax Expense - Continuing Operations | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Expense - Continuing Operations | 14. Income Tax Expense – Continuing Operations The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company’s consolidated statements of income for the three month periods ended March 31, 2017 and 2016: Three Months Ended March 31, (in thousands) 2017 2016 Income Before Income Taxes – Continuing Operations $ 25,892 $ 19,982 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 10,098 7,793 Increases (Decreases) in Tax from: Federal Production Tax Credits (2,052 ) (1,686 ) Excess Tax Deduction – 2014 Performance Share Awards (697 ) — Section 199 Domestic Production Activities Deduction (330 ) (104 ) Corporate Owned Life Insurance (294 ) (92 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (212 ) (212 ) Employee Stock Ownership Plan Dividend Deduction (172 ) (158 ) Other Items – Net 22 (49 ) Income Tax Expense – Continuing Operations $ 6,363 $ 5,492 Effective Income Tax Rate – Continuing Operations 24.6 % 27.5 % The following table summarizes the activity related to our unrecognized tax benefits: (in thousands) 2017 2016 Balance on January 1 $ 891 $ 468 Increases Related to Tax Positions for Prior Years — — Increases Related to Tax Positions for Current Year 43 16 Uncertain Positions Resolved During Year — — Balance on March 31 $ 934 $ 484 The balance of unrecognized tax benefits as of March 31, 2017 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2017 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of March 31, 2017. The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of March 31, 2017, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income taxes. |
Discontinued Operations
Discontinued Operations | 3 Months Ended |
Mar. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | 16. Discontinued Operations Included in discontinued operations are activities related to the Company’s former wind tower manufacturing business and dock and boatlift company. Included in liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow: (in thousands) 2017 2016 Warranty Reserve Balance, January 1 $ 1,369 $ 2,103 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year (1 ) — Decrease in Warranty Estimates for Prior Years (100 ) — Warranty Reserve Balance, March 31 $ 1,268 $ 2,103 The warranty reserve balances as of March 31, 2017 relate to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried one to fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies. Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company’s consolidated net income and financial condition. |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Revenue Recognition | Revenue Recognition Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized. For the Company’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such product. The shipping terms used in these instances are FOB shipping point. |
Agreements Subject to Legally Enforceable Netting Arrangements | Agreements Subject to Legally Enforceable Netting Arrangements The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. |
Fair Value Measurements | Fair Value Measurements The Company follows Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX). Level 2 – Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities. Level 3 – Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts. The following tables present, for each of the hierarchy levels, the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016: March 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,590 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,345 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 828 Total Assets $ 828 $ 7,935 December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: Government-Backed and Government-Sponsored Enterprises’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company |
Coyote Station Lignite Supply Agreement - Variable Interest Entity | Coyote Station Lignite Supply Agreement – Variable Interest Entity If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of March 31, 2017 could be as high as $59.7 million, OTP’s 35% share of unrecovered costs. |
Inventories | Inventories Inventories, valued at the lower of cost or net realizable value, consist of the following: March 31, December 31, (in thousands) 2017 2016 Finished Goods $ 24,018 $ 27,755 Work in Process 12,801 11,754 Raw Material, Fuel and Supplies 44,654 44,231 Total Inventories $ 81,473 $ 83,740 |
Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets An assessment of the carrying amounts of goodwill of the Company’s operating units as of December 31, 2016 indicated the fair values are substantially in excess of their respective book values and not impaired. The following table indicates there were no changes to goodwill by business segment during the first three months of 2017: (in thousands) Gross Balance Accumulated Balance Adjustments to Balance Manufacturing $ 18,270 $ — $ 18,270 $ — $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 37,572 $ — $ 37,572 $ — $ 37,572 Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC Topic 360-10-35, Property, Plant, and Equipment—Overall—Subsequent Measurement The following table summarizes the components of the Company’s intangible assets at March 31, 2017 and December 31, 2016: March 31, 2017 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,144 $ 14,347 33-221 months Covenant not to Compete 590 311 279 17 months Total $ 23,081 $ 8,455 $ 14,626 December 31, 2016 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 The amortization expense for these intangible assets was: Three Months Ended March 31, (in thousands) 2017 2016 Amortization Expense – Intangible Assets $ 332 $ 357 The estimated annual amortization expense for these intangible assets for the next five years is: (in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099 |
Supplemental Disclosures of Cash Flow Information | Supplemental Disclosures of Cash Flow Information As of March 31, (in thousands) 2017 2016 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,811 $ 24,618 |
New Accounting Standards Adopted | New Accounting Standards Adopted Accounting Standards Update (ASU) 2015-11 Inventory (Topic 330): Simplifying the Measurement of Inventory, |
New Accounting Standards Pending Adoption | New Accounting Standards Pending Adoption ASU 2014-09 Revenue from Contracts with Customers (Topic 606) Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial application. As of March 31, 2017 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is evaluating transition options. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09. The treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard. The Company does not plan to adopt the updated guidance prior to January 1, 2018. ASU 2016-02 Leases (Topic 842) ASU 2017-04 Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment The amendments in ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost. Topic 715, Compensation—Retirement Benefits , The majority of the Company’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU 2017-07 may have on its consolidated financial statements, financial position and results of operations and is determining what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated income statements upon adoption of the amendments in ASU 2017-07. The Company does not plan to adopt the updates in ASU 2017-07 prior to the first quarter of 2018, the required effective period for application of the updates by the Company. |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of assets and liabilities that are measured at fair value on a recurring basis | March 31, 2017 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,590 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,345 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 828 Total Assets $ 828 $ 7,935 December 31, 2016 (in thousands) Level 1 Level 2 Level 3 Assets: Investments: Corporate Debt Securities – Held by Captive Insurance Company $ 5,280 Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company 2,945 Other Assets: Money Market and Mutual Funds – Nonqualified Retirement Savings Plan $ 849 Total Assets $ 849 $ 8,225 |
Schedule of inventories | March 31, December 31, (in thousands) 2017 2016 Finished Goods $ 24,018 $ 27,755 Work in Process 12,801 11,754 Raw Material, Fuel and Supplies 44,654 44,231 Total Inventories $ 81,473 $ 83,740 |
Schedule of changes to goodwill by business segment | (in thousands) Gross Balance Accumulated Balance Adjustments to Balance Manufacturing $ 18,270 $ — $ 18,270 $ — $ 18,270 Plastics 19,302 — 19,302 — 19,302 Total $ 37,572 $ — $ 37,572 $ — $ 37,572 |
Schedule of components of intangible assets | March 31, 2017 (in thousands) Gross Carrying Accumulated Net Carrying Remaining Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 8,144 $ 14,347 33-221 months Covenant not to Compete 590 311 279 17 months Total $ 23,081 $ 8,455 $ 14,626 December 31, 2016 (in thousands) Amortizable Intangible Assets: Customer Relationships $ 22,491 $ 7,861 $ 14,630 36-224 months Covenant not to Compete 590 262 328 20 months Total $ 23,081 $ 8,123 $ 14,958 |
Schedule of amortization expense for intangible assets | Three Months Ended March 31, (in thousands) 2017 2016 Amortization Expense – Intangible Assets $ 332 $ 357 |
Schedule of estimated annual amortization expense for intangible assets | (in thousands) 2017 2018 2019 2020 2021 Estimated Amortization Expense – Intangible Assets $ 1,330 $ 1,264 $ 1,133 $ 1,099 $ 1,099 |
Schedule of supplemental disclosure of cash flow information | As of March 31, (in thousands) 2017 2016 Noncash Investing Activities: Transactions Related to Capital Additions not Settled in Cash $ 10,811 $ 24,618 |
Segment Information (Tables)
Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of information by business segments | Operating Revenue Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 118,551 $ 112,994 Manufacturing 58,417 59,820 Plastics 37,157 33,437 Intersegment Eliminations (8 ) (9 ) Total $ 214,117 $ 206,242 Interest Charges Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 6,386 $ 6,284 Manufacturing 554 992 Plastics 153 244 Corporate and Intersegment Eliminations 369 474 Total $ 7,462 $ 7,994 Income Taxes Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 6,062 $ 4,612 Manufacturing 1,055 1,019 Plastics 1,390 1,367 Corporate (2,144 ) (1,506 ) Total $ 6,363 $ 5,492 Net Income (Loss) Three Months Ended March 31, (in thousands) 2017 2016 Electric $ 15,560 $ 12,538 Manufacturing 2,172 1,853 Plastics 2,437 2,152 Corporate (640 ) (2,053 ) Discontinued Operations 56 30 Total $ 19,585 $ 14,520 Identifiable Assets March 31, December 31, (in thousands) 2017 2016 Electric $ 1,630,071 $ 1,622,231 Manufacturing 170,805 166,525 Plastics 91,049 84,592 Corporate 38,781 39,037 Total $ 1,930,706 $ 1,912,385 |
Rate and Regulatory Matters (Ta
Rate and Regulatory Matters (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Rate and Regulatory Matters [Abstract] | |
Schedule of request and interim rate information | ($ in thousands) Annualized or Actual Through Revenue Increase Requested $ 19,296 Increase Percentage Requested 9.80 % Jurisdictional Rate Base $ 483,000 Interim Revenue Increase (subject to refund) $ 16,816 $ 15,335 |
Schedule of information on status of updates for previous periods | Rate Rider R - Request Date Effective Date Annual Revenue ($000s) Rate Minnesota Conservation Improvement Program 2016 Incentive and Cost Recovery R – March 31, 2017 October 1, 2017 $ 9,868 $0.00754/kwh 2015 Incentive and Cost Recovery A – July 19, 2016 October 1, 2016 $ 8,590 $0.00275/kwh 2014 Incentive and Cost Recovery A – July 10, 2015 October 1, 2015 $ 8,689 $0.00287/kwh Transmission Cost Recovery 2016 Annual Update 1 A – July 5, 2016 September 1, 2016 $ 4,736 Various 2015 Annual Update A – March 9, 2016 April 1, 2016 $ 7,203 Various 2014 Annual Update A – February 18, 2015 March 1, 2015 $ 8,388 Various Environmental Cost Recovery 2016 Annual Update 1 A – July 5, 2016 September 1, 2016 $ 11,884 6.927% of Rev 2015 Annual Update A – March 9, 2016 October 1, 2015 $ 12,104 7.006% of Rev North Dakota Renewable Resource Adjustment 2016 Annual Update A – March 15, 2017 April 1, 2017 $ 9,156 7.005% of Rev 2015 Annual Update A – June 22, 2016 July 1, 2016 $ 9,262 7.573% of Rev 2014 Annual Update A – March 25, 2015 April 1, 2015 $ 5,441 4.069% of Rev Transmission Cost Recovery 2016 Annual Update A – December 14, 2016 January 1, 2017 $ 6,916 Various 2015 Annual Update A – December 16, 2015 January 1, 2016 $ 9,985 Various Environmental Cost Recovery 2017 Annual Update R – March 31, 2017 July 1 2017 $ 9,917 7.633% of base 2016 Annual Update A – June 22, 2016 July 1, 2016 $ 10,359 7.904% of base 2015 Annual Update A – June 17, 2015 July 1, 2015 $ 12,249 9.193% of base South Dakota Transmission Cost Recovery 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 2014 Annual Update A – February 13, 2015 March 1, 2015 $ 1,538 Various Environmental Cost Recovery 2016 Annual Update A – October 26, 2016 November 1, 2016 $ 2,238 $0.00536/kwh 2015 Annual Update A – October 15, 2015 November 1, 2015 $ 2,728 $0.00643/kwh 1 |
Schedule of revenues recorded under rate riders | Rate Rider (in thousands) 2017 2016 Minnesota Conservation Improvement Program Costs and Incentives 1 $ 1,966 $ 2,506 Transmission Cost Recovery 2,170 2,276 Environmental Cost Recovery 2,824 3,082 North Dakota Renewable Resource Adjustment 1,770 2,059 Transmission Cost Recovery 2,511 2,236 Environmental Cost Recovery 2,488 2,811 South Dakota Transmission Cost Recovery 441 651 Environmental Cost Recovery 597 633 Conservation Improvement Program Costs and Incentives 240 159 1 |
Regulatory Assets and Liabili26
Regulatory Assets and Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of amount of regulatory assets and liabilities | March 31, 2017 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,443 $ 106,656 $ 113,099 see below Deferred Marked-to-Market Losses 1 4,063 5,452 9,515 45 months Conservation Improvement Program Costs and Incentives 2 3,745 5,735 9,480 30 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,276 6,276 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 739 1,926 2,665 49 months Debt Reacquisition Premiums 1 301 1,150 1,451 186 months Deferred Income Taxes 1 — 1,020 1,020 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 954 — 954 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 727 62 789 24 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 517 617 74 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 426 59 485 21 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 251 115 366 21 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 106 — 106 11 months Minnesota Transmission Cost Recovery Rider Accrued Revenues 2 95 — 95 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 23 — 23 6 months Total Regulatory Assets $ 17,973 $ 128,968 $ 146,941 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 81,314 $ 81,314 asset lives Refundable Fuel Clause Adjustment Revenues 2,119 — 2,119 12 months North Dakota Transmission Cost Recovery Rider Accrued Refund 1,545 — 1,545 12 months Deferred Income Taxes — 785 785 asset lives Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 30 741 13 months Minnesota Environmental Cost Recovery Rider Accrued Refund 631 — 631 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 354 — 354 12 months North Dakota Environmental Cost Recovery Rider Accrued Refund 299 — 299 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 33 99 132 21 months South Dakota Transmission Cost Recovery Rider Accrued Refund 8 — 8 12 months Other 6 88 94 201 months Total Regulatory Liabilities $ 5,706 $ 82,316 $ 88,022 Net Regulatory Asset Position $ 12,267 $ 46,652 $ 58,919 1 2 December 31, 2016 Remaining (in thousands) Current Long-Term Total Refund Period Regulatory Assets: Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits 1 $ 6,443 $ 108,267 $ 114,710 see below Deferred Marked-to-Market Losses 1 4,063 6,467 10,530 48 months Conservation Improvement Program Costs and Incentives 2 4,836 5,158 9,994 21 months Accumulated ARO Accretion/Depreciation Adjustment 1 — 6,153 6,153 asset lives Big Stone II Unrecovered Project Costs – Minnesota 1 778 2,087 2,865 52 months Recoverable Fuel and Purchased Power Costs 1 1,798 — 1,798 12 months Debt Reacquisition Premiums 1 325 1,214 1,539 189 months Deferred Income Taxes 1 — 1,014 1,014 asset lives Minnesota Deferred Rate Case Expenses Subject to Recovery 1 1,082 — 1,082 12 months North Dakota Renewable Resource Rider Accrued Revenues 2 1,319 482 1,801 15 months Big Stone II Unrecovered Project Costs – South Dakota 2 100 543 643 77 months North Dakota Transmission Cost Recovery Rider Accrued Revenues 2 — 568 568 24 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up 2 333 — 333 12 months South Dakota Transmission Cost Recovery Rider Accrued Revenues 2 73 141 214 14 months North Dakota Environmental Cost Recovery Rider Accrued Revenues 2 113 — 113 12 months Minnesota Renewable Resource Rider Accrued Revenues 2 34 — 34 9 months Total Regulatory Assets $ 21,297 $ 132,094 $ 153,391 Regulatory Liabilities: Accumulated Reserve for Estimated Removal Costs – Net of Salvage $ — $ 80,404 $ 80,404 asset lives North Dakota Transmission Cost Recovery Rider Accrued Refund 1,381 782 2,163 24 months Deferred Income Taxes — 818 818 asset lives Revenue for Rate Case Expenses Subject to Refund – Minnesota 711 208 919 16 months Minnesota Transmission Cost Recovery Rider Accrued Refund 757 — 757 12 months Minnesota Environmental Cost Recovery Rider Accrued Refund 139 — 139 12 months South Dakota Environmental Cost Recovery Rider Accrued Refund 285 — 285 12 months MISO Schedule 26/26A Transmission Cost Recovery Rider True-up — 132 132 24 months Other 21 89 110 204 months Total Regulatory Liabilities $ 3,294 $ 82,433 $ 85,727 Net Regulatory Asset Position $ 18,003 $ 49,661 $ 67,664 1 2 |
Open Contract Positions Subje27
Open Contract Positions Subject to Legally Enforceable Netting Arrangements (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Open Contract Positions Subject To Legally Enforceable Netting Arrangements [Abstract] | |
Schedule of derivative asset and liability balances subject to legally enforceable netting arrangements | (in thousands) March 31, December 31, Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements $ — $ — Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements (14,590 ) (17,382 ) Net Balance Subject to Legally Enforceable Netting Arrangements $ (14,590 ) $ (17,382 ) |
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions | (in thousands) March 31, December 31, Loss Contracts Covered by Deposited Funds or Letters of Credit $ — $ — Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade 1 14,590 17,382 Total Loss Contracts based on Current Market Values $ 14,590 $ 17,382 1 Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade $ 14,590 $ 17,382 Offsetting Gains with Counterparties under Master Netting Agreements — — Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 14,590 $ 17,382 |
Reconciliation of Common Shar28
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Stockholders Equity and Earnings Per Share [Abstract] | |
Schedule of reconciliation of common shareholders' equity | (in thousands) Par Value, Premium Retained Accumulated Total Balance, December 31, 2016 $ 196,741 $ 337,684 $ 139,479 $ (3,800 ) $ 670,104 Common Stock Issuances, Net of Expenses 837 1,727 2,564 Common Stock Retirements (234 ) (1,525 ) (1,759 ) Net Income 19,585 19,585 Other Comprehensive Income 105 105 Employee Stock Incentive Plans Expense 1,150 1,150 Common Dividends ($0.32 per share) (12,626 ) (12,626 ) Balance, March 31, 2017 $ 197,344 $ 339,036 $ 146,438 $ (3,695 ) $ 679,123 |
Schedule of common shares outstanding from December 31, 2015 through March 31, 2016 | Common Shares Outstanding, December 31, 2016 39,348,136 Issuances: Executive Stock Performance Awards (2014 shares earned) 89,291 Automatic Dividend Reinvestment and Share Purchase Plan: Dividends Reinvested 36,320 Cash Invested 11,750 Employee Stock Ownership Plan 14,835 Vesting of Restricted Stock Units 9,975 Employee Stock Purchase Plan: Cash Invested — Dividends Reinvested 5,131 Retirements: Shares Withheld for Individual Income Tax Requirements (46,634 ) Common Shares Outstanding, March 31, 2017 39,468,804 |
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted | 2017 2016 Weighted Average Common Shares Outstanding – Basic 39,350,802 37,936,943 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 201,639 46,885 Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees 57,873 39,841 Nonvested Restricted Shares 27,069 17,776 Shares Expected to be Issued Under the Deferred Compensation Program for Directors 3,342 3,763 Total Dilutive Shares 289,923 108,265 Weighted Average Common Shares Outstanding – Diluted 39,640,725 38,045,208 |
Share-Based Payments (Tables)
Share-Based Payments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | |
Schedule of stock incentive awards granted | Award Shares/Units Weighted Vesting Restricted Stock Units Granted 15,900 $ 37.65 25% per year through February 6, 2021 Stock Performance Awards Granted 59,500 $ 31.00 December 31, 2019 |
Schedule of compensation expense under stock-based payment programs | Three months ended March 31, (in thousands) 2017 2016 Stock Performance Awards Granted to Executive Officers $ 649 $ 537 Restricted Stock Units Granted to Executive Officers 264 245 Restricted Stock Granted to Executive Officers 22 29 Restricted Stock Granted to Directors 128 107 Restricted Stock Units Granted to Non-Executive Employees 87 64 Employee Stock Purchase Plan (15% discount) — 44 Totals $ 1,150 $ 1,026 |
Short-Term and Long-Term Borr30
Short-Term and Long-Term Borrowings (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of lines of credit | (in thousands) Line Limit In Use on Restricted due to Available on Available on Otter Tail Corporation Credit Agreement $ 130,000 $ 12,825 $ — $ 117,175 $ 130,000 OTP Credit Agreement 170,000 46,351 50 123,599 127,067 Total $ 300,000 $ 59,176 $ 50 $ 240,774 $ 257,067 |
Schedule of short-term and long-term debt outstanding | March 31, 2017 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 46,351 $ 12,825 $ 59,176 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 12,000 $ 12,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 86 86 Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 799 799 Total $ 445,000 $ 92,885 $ 537,885 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,981 12,211 45,192 Unamortized Long-Term Debt Issuance Costs 1,801 520 2,321 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,218 $ 80,154 $ 490,372 Total Short-Term and Long-Term Debt (with current maturities) $ 489,550 $ 105,190 $ 594,740 December 31, 2016 (in thousands) OTP Otter Tail Otter Tail Short-Term Debt $ 42,883 $ — $ 42,883 Long-Term Debt: Term Loan, LIBOR plus 0.90%, due February 5, 2018 $ 15,000 $ 15,000 3.55% Guaranteed Senior Notes, due December 15, 2026 80,000 80,000 Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 $ 33,000 33,000 Senior Unsecured Notes 4.63%, due December 1, 2021 140,000 140,000 Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 30,000 30,000 Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 42,000 42,000 Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 60,000 60,000 Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 50,000 50,000 Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 90,000 90,000 North Dakota Development Note, 3.95%, due April 1, 2018 106 106 PACE Note, 2.54%, due March 18, 2021 836 836 Total $ 445,000 $ 95,942 $ 540,942 Less: Current Maturities net of Unamortized Debt Issuance Costs 32,970 231 33,201 Unamortized Long-Term Debt Issuance Costs 1,861 539 2,400 Total Long-Term Debt net of Unamortized Debt Issuance Costs $ 410,169 $ 95,172 $ 505,341 Total Short-Term and Long-Term Debt (with current maturities) $ 486,022 $ 95,403 $ 581,425 |
Pension Plan and Other Postre31
Pension Plan and Other Postretirement Benefits (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Pension Plan | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 1,407 $ 1,382 Interest Cost on Projected Benefit Obligation 3,534 3,522 Expected Return on Assets (4,807 ) (4,867 ) Amortization of Prior-Service Cost: From Regulatory Asset 30 47 From Other Comprehensive Income 1 1 1 Amortization of Net Actuarial Loss: From Regulatory Asset 1,273 1,227 From Other Comprehensive Income 1 31 31 Net Periodic Pension Cost $ 1,469 $ 1,343 1 |
Executive Survivor and Supplemental Retirement Plan | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 73 $ 63 Interest Cost on Projected Benefit Obligation 422 417 Amortization of Prior-Service Cost: From Regulatory Asset 4 4 From Other Comprehensive Income 1 9 9 Amortization of Net Actuarial Loss: From Regulatory Asset 71 73 From Other Comprehensive Income 2 110 112 Net Periodic Pension Cost $ 689 $ 678 1 Electric Operation and Maintenance Expenses $ 4 $ 4 Other Nonelectric Expenses 5 5 2 Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44 |
Postretirement Benefits | |
Schedule of components of net periodic postretirement benefit cost | Three Months Ended March 31, (in thousands) 2017 2016 Service Cost—Benefit Earned During the Period $ 356 $ 306 Interest Cost on Projected Benefit Obligation 678 541 Amortization of Prior-Service Costs: From Regulatory Asset — 33 From Other Comprehensive Income 1 — 1 Amortization of Net Actuarial Loss: From Regulatory Asset 233 — From Other Comprehensive Income 1 6 — Net Periodic Postretirement Benefit Cost $ 1,273 $ 881 Effect of Medicare Part D Subsidy $ (140 ) $ (257 ) 1 Corporate cost included in Other Nonelectric Expenses. |
Fair Value of Financial Instr32
Fair Value of Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of long-term debt including current maturities | March 31, 2017 December 31, 2016 (in thousands) Carrying Fair Value Carrying Fair Value Short-Term Debt (59,176 ) (59,176 ) (42,883 ) (42,883 ) Long-Term Debt including Current Maturities (535,564 ) (582,743 ) (538,542 ) (583,835 ) |
Income Tax Expense - Continui33
Income Tax Expense - Continuing Operations (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of income from continuing operations before income taxes and income tax expense | Three Months Ended March 31, (in thousands) 2017 2016 Income Before Income Taxes – Continuing Operations $ 25,892 $ 19,982 Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) 10,098 7,793 Increases (Decreases) in Tax from: Federal Production Tax Credits (2,052 ) (1,686 ) Excess Tax Deduction – 2014 Performance Share Awards (697 ) — Section 199 Domestic Production Activities Deduction (330 ) (104 ) Corporate Owned Life Insurance (294 ) (92 ) North Dakota Wind Tax Credit Amortization – Net of Federal Taxes (212 ) (212 ) Employee Stock Ownership Plan Dividend Deduction (172 ) (158 ) Other Items – Net 22 (49 ) Income Tax Expense – Continuing Operations $ 6,363 $ 5,492 Effective Income Tax Rate – Continuing Operations 24.6 % 27.5 % |
Schedule of activity related to unrecognized tax benefits | (in thousands) 2017 2016 Balance on January 1 $ 891 $ 468 Increases Related to Tax Positions for Prior Years — — Increases Related to Tax Positions for Current Year 43 16 Uncertain Positions Resolved During Year — — Balance on March 31 $ 934 $ 484 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Schedule of warranty reserves | (in thousands) 2017 2016 Warranty Reserve Balance, January 1 $ 1,369 $ 2,103 Additional Provision for Warranties Made During the Year — — Settlements Made During the Year (1 ) — Decrease in Warranty Estimates for Prior Years (100 ) — Warranty Reserve Balance, March 31 $ 1,268 $ 2,103 |
Summary of Significant Accoun35
Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Level 1 | ||
Assets: | ||
Total Assets | $ 828 | $ 849 |
Level 1 | Money Market and Mutual Funds | ||
Assets: | ||
Other Assets - Nonqualified Retirement Savings Plan | 828 | 849 |
Level 2 | ||
Assets: | ||
Total Assets | 7,935 | 8,225 |
Level 2 | Corporate Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | 5,590 | 5,280 |
Level 2 | Government-Backed and Government-Sponsored Enterprises' Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | $ 2,345 | $ 2,945 |
Summary of Significant Accoun36
Summary of Significant Accounting Policies - Inventories (Details 1) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Accounting Policies [Abstract] | ||
Finished Goods | $ 24,018 | $ 27,755 |
Work in Process | 12,801 | 11,754 |
Raw Material, Fuel and Supplies | 44,654 | 44,231 |
Total Inventories | $ 81,473 | $ 83,740 |
Summary of Significant Accoun37
Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 2) $ in Thousands | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2016 | $ 37,572 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2016 | 37,572 |
Adjustments to Goodwill in 2017 | |
Balance (net of impairments) March 31, 2017 | 37,572 |
Manufacturing | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2016 | 18,270 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2016 | 18,270 |
Adjustments to Goodwill in 2017 | |
Balance (net of impairments) March 31, 2017 | 18,270 |
Plastics | |
Goodwill [Roll Forward] | |
Gross Balance December 31, 2016 | 19,302 |
Accumulated Impairments | |
Balance (net of impairments) December 31, 2016 | 19,302 |
Adjustments to Goodwill in 2017 | |
Balance (net of impairments) March 31, 2017 | $ 19,302 |
Summary of Significant Accoun38
Summary of Significant Accounting Policies - Components of intangible assets (Details 3) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 23,081 | $ 23,081 |
Accumulated Amortization | 8,455 | 8,123 |
Net Carrying Amount | 14,626 | 14,958 |
Customer Relationships | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 22,491 | 22,491 |
Accumulated Amortization | 8,144 | 7,861 |
Net Carrying Amount | $ 14,347 | $ 14,630 |
Customer Relationships | Minimum | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods | 33 months | 36 months |
Customer Relationships | Maximum | ||
Amortizable Intangible Assets: | ||
Remaining Amortization Periods | 221 months | 224 months |
Covenant not to Compete | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | $ 590 | $ 590 |
Accumulated Amortization | 311 | 262 |
Net Carrying Amount | $ 279 | $ 328 |
Remaining Amortization Periods | 17 months | 20 months |
Summary of Significant Accoun39
Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 4) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Accounting Policies [Abstract] | ||
Amortization Expense - Intangible Assets | $ 332 | $ 357 |
Summary of Significant Accoun40
Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 5) $ in Thousands | Mar. 31, 2017USD ($) |
Estimated Amortization Expense - Intangible Assets | |
2,017 | $ 1,330 |
2,018 | 1,264 |
2,019 | 1,133 |
2,020 | 1,099 |
2,021 | $ 1,099 |
Summary of Significant Accoun41
Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 6) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2016 |
Noncash Investing Activities: | ||
Transactions Related to Capital Additions not Settled in Cash | $ 10,811 | $ 24,618 |
Summary of Significant Accoun42
Summary of Significant Accounting Policies (Detail Textuals) - Coyote Creek Mining Company, L.L.C. (CCMC) - Lignite Sales Agreement - Otter Tail Power Company $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Significant Accounting Policies [Line Items] | |
Maximum exposure to loss as a result of involvement with CCMC | $ 59.7 |
Percentage of development period costs, development fees and capital charge incurred by CCMC | 35.00% |
Segment Information - Informati
Segment Information - Information on continuing operations for business segments (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Segment Reporting Information [Line Items] | ||
Operating Revenue | $ 214,117 | $ 206,242 |
Interest Charges | 7,462 | 7,994 |
Income Taxes | 6,363 | 5,492 |
Net Income (Loss) | 19,585 | 14,520 |
Intersegment Eliminations | ||
Segment Reporting Information [Line Items] | ||
Operating Revenue | (8) | (9) |
Corporate and Intersegment Eliminations | ||
Segment Reporting Information [Line Items] | ||
Interest Charges | 369 | 474 |
Corporate | ||
Segment Reporting Information [Line Items] | ||
Income Taxes | (2,144) | (1,506) |
Net Income (Loss) | (640) | (2,053) |
Discontinued Operations | ||
Segment Reporting Information [Line Items] | ||
Net Income (Loss) | 56 | 30 |
Electric | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Operating Revenue | 118,551 | 112,994 |
Interest Charges | 6,386 | 6,284 |
Income Taxes | 6,062 | 4,612 |
Net Income (Loss) | 15,560 | 12,538 |
Manufacturing | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Operating Revenue | 58,417 | 59,820 |
Interest Charges | 554 | 992 |
Income Taxes | 1,055 | 1,019 |
Net Income (Loss) | 2,172 | 1,853 |
Plastics | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Operating Revenue | 37,157 | 33,437 |
Interest Charges | 153 | 244 |
Income Taxes | 1,390 | 1,367 |
Net Income (Loss) | $ 2,437 | $ 2,152 |
Segment Information - Total ass
Segment Information - Total assets by business segment (Details 1) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | ||
Assets | $ 1,930,706 | $ 1,912,385 |
Corporate | ||
Segment Reporting Information [Line Items] | ||
Assets | 38,781 | 39,037 |
Electric | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | 1,630,071 | 1,622,231 |
Manufacturing | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | 170,805 | 166,525 |
Plastics | Operating Segments | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 91,049 | $ 84,592 |
Segment Information (Detail Tex
Segment Information (Detail Textuals) - Operating revenues | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | |||
Operating revenues, benchmark description | No single customer accounted for over 10% of the Company's consolidated revenues | ||
UNITED STATES | |||
Concentration Risk [Line Items] | |||
Operating revenues, percentage | 98.40% | 97.60% |
Segment Information (Detail T46
Segment Information (Detail Textuals 1) | 3 Months Ended |
Mar. 31, 2017Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 3 |
Rate and Regulatory Matters - S
Rate and Regulatory Matters - Summary of interim rate information (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Public Utilities, General Disclosures [Line Items] | |
Interim Revenue Increase (subject to refund) | $ 15,335 |
2017 Test Year Allocation | |
Public Utilities, General Disclosures [Line Items] | |
Revenue Increase Requested | $ 19,296 |
Increase Percentage Requested | 9.80% |
Jurisdictional Rate Base | $ 483,000 |
Interim Revenue Increase (subject to refund) | $ 16,816 |
Rate and Regulatory Matters -48
Rate and Regulatory Matters - Summary of status of updates for previous two years for various rate riders (Details 1) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 214,117 | $ 206,242 | |
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | [1] | $ 1,966 | 2,506 |
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2016 Incentive and Cost Recovery | |||
Public Utilities, General Disclosures [Line Items] | |||
R - Request Date | Mar. 31, 2017 | ||
Effective Date Requested or Approved | Oct. 1, 2017 | ||
Annual Revenue | $ 9,868 | ||
Rate | $0.00754/kwh | ||
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2015 Incentive and Cost Recovery | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Jul. 19, 2016 | ||
Effective Date Requested or Approved | Oct. 1, 2016 | ||
Annual Revenue | $ 8,590 | ||
Rate | $0.00275/kwh | ||
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | 2014 Incentive and Cost Recovery | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Jul. 10, 2015 | ||
Effective Date Requested or Approved | Oct. 1, 2015 | ||
Annual Revenue | $ 8,689 | ||
Rate | $0.00287/kwh | ||
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 2,170 | 2,276 | |
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | [2] | Jul. 5, 2016 | |
Effective Date Requested or Approved | [2] | Sep. 1, 2016 | |
Annual Revenue | [2] | $ 4,736 | |
Rate | [2] | Various | |
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Mar. 9, 2016 | ||
Effective Date Requested or Approved | Apr. 1, 2016 | ||
Annual Revenue | $ 7,203 | ||
Rate | Various | ||
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | 2014 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Feb. 18, 2015 | ||
Effective Date Requested or Approved | Mar. 1, 2015 | ||
Annual Revenue | $ 8,388 | ||
Rate | Various | ||
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 2,824 | 3,082 | |
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | [2] | Jul. 5, 2016 | |
Effective Date Requested or Approved | [2] | Sep. 1, 2016 | |
Annual Revenue | [2] | $ 11,884 | |
Rate | [2] | 6.927% of Rev | |
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Mar. 9, 2016 | ||
Effective Date Requested or Approved | Oct. 1, 2015 | ||
Annual Revenue | $ 12,104 | ||
Rate | 7.006% of Rev | ||
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 1,770 | 2,059 | |
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Mar. 15, 2017 | ||
Effective Date Requested or Approved | Apr. 1, 2017 | ||
Annual Revenue | $ 9,156 | ||
Rate | 7.005% of Rev | ||
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Jun. 22, 2016 | ||
Effective Date Requested or Approved | Jul. 1, 2016 | ||
Annual Revenue | $ 9,262 | ||
Rate | 7.573% of Rev | ||
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | 2014 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Mar. 25, 2015 | ||
Effective Date Requested or Approved | Apr. 1, 2015 | ||
Annual Revenue | $ 5,441 | ||
Rate | 4.069% of Rev | ||
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 2,511 | 2,236 | |
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Dec. 14, 2016 | ||
Effective Date Requested or Approved | Jan. 1, 2017 | ||
Annual Revenue | $ 6,916 | ||
Rate | Various | ||
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Dec. 16, 2015 | ||
Effective Date Requested or Approved | Jan. 1, 2016 | ||
Annual Revenue | $ 9,985 | ||
Rate | Various | ||
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 2,488 | 2,811 | |
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2017 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
R - Request Date | Mar. 31, 2017 | ||
Effective Date Requested or Approved | Jul. 1, 2017 | ||
Annual Revenue | $ 9,917 | ||
Rate | 7.633% of base | ||
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Jun. 22, 2016 | ||
Effective Date Requested or Approved | Jul. 1, 2016 | ||
Annual Revenue | $ 10,359 | ||
Rate | 7.904% of base | ||
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Jun. 17, 2015 | ||
Effective Date Requested or Approved | Jul. 1, 2015 | ||
Annual Revenue | $ 12,249 | ||
Rate | 9.193% of base | ||
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 240 | 159 | |
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 441 | 651 | |
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Feb. 17, 2017 | ||
Effective Date Requested or Approved | Mar. 1, 2017 | ||
Annual Revenue | $ 2,053 | ||
Rate | Various | ||
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Feb. 12, 2016 | ||
Effective Date Requested or Approved | Mar. 1, 2016 | ||
Annual Revenue | $ 1,895 | ||
Rate | Various | ||
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | 2014 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Feb. 13, 2015 | ||
Effective Date Requested or Approved | Mar. 1, 2015 | ||
Annual Revenue | $ 1,538 | ||
Rate | Various | ||
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Annual Revenue | $ 597 | $ 633 | |
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | 2016 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Oct. 26, 2016 | ||
Effective Date Requested or Approved | Nov. 1, 2016 | ||
Annual Revenue | $ 2,238 | ||
Rate | $0.00536/kwh | ||
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | 2015 Annual Update | |||
Public Utilities, General Disclosures [Line Items] | |||
A - Approval Date | Oct. 15, 2015 | ||
Effective Date Requested or Approved | Nov. 1, 2015 | ||
Annual Revenue | $ 2,728 | ||
Rate | $0.00643/kwh | ||
[1] | Includes MNCIP costs recovered in base rates. | ||
[2] | Approved on a provisional basis and subject to change based on comments from the MNDOC. |
Rate and Regulatory Matters -49
Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 2) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | $ 214,117 | $ 206,242 | |
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | [1] | 1,966 | 2,506 |
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 2,170 | 2,276 | |
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 2,824 | 3,082 | |
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 1,770 | 2,059 | |
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 2,511 | 2,236 | |
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 2,488 | 2,811 | |
Otter Tail Power Company | South Dakota | Conservation Improvement Program Costs and Incentives | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 240 | 159 | |
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | 441 | 651 | |
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | |||
Public Utilities, General Disclosures [Line Items] | |||
Revenues recorded under rate riders | $ 597 | $ 633 | |
[1] | Includes MNCIP costs recovered in base rates. |
Rate and Regulatory Matters (De
Rate and Regulatory Matters (Detail Textuals) - Otter Tail Power Company $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($)kVmi | |
Big Stone South - Brookings MVP | |
Public Utilities, General Disclosures [Line Items] | |
Project costs incurred to date | $ | $ 64 |
Percentage of assets of project | 100.00% |
Expanded capacity of projects | kV | 345 |
Extended distance of transmission line | mi | 70 |
Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | |
Public Utilities, General Disclosures [Line Items] | |
Project costs incurred to date | $ | $ 57.9 |
Percentage of assets of project | 100.00% |
Expanded capacity of projects | kV | 345 |
Extended distance of transmission line | mi | 163 |
Rate and Regulatory Matters (51
Rate and Regulatory Matters (Detail Textuals 1) $ in Millions | Apr. 14, 2016 | Feb. 16, 2016 | Apr. 25, 2011USD ($) | Mar. 31, 2017USD ($)Customer | May 25, 2016 |
Otter Tail Power Company | 2016 General Rate Case | Rebuttal Testimony | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 10.05% | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Incentives net benefit, 2017 | 13.50% | ||||
Incentives net benefit, 2018 | 12.00% | ||||
Incentives net benefit, 2019 | 10.00% | ||||
Assumed savings of utility | 1.70% | ||||
Percentage of reduction in financial incentive | 50.00% | ||||
Number of large customers who requests for exemption | Customer | 2 | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Financial incentive request approved | $ 3 | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2015 | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Financial incentive request approved | 4.3 | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2016 | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Amount of financial incentive requested | 5 | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case | |||||
Public Utilities, General Disclosures [Line Items] | |||||
General rate revenue increase requested | $ 5 | ||||
Percentage of increase in base rate revenue requested | 1.60% | ||||
Public utilities allowed rate of return on rate base prior to approval of increase in base rate | 8.33% | ||||
Public utilities allowed rate of return on rate base subsequent to approval of increase in base rate | 8.61% | ||||
Public utilities allowed rate of return on equity prior to approval of increase in base rate | 10.43% | ||||
Public utilities allowed rate of return on equity subsequent to approval of increase in base rate | 10.74% | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public utilities allowed rate of return on rate base | 8.07% | ||||
Public utilities allowed rate of return on equity increase in base rate | 10.40% | ||||
Percentage of capital | 52.50% | ||||
Authorized a revenue increase | $ 12.3 | ||||
Increase in base rate revenue | 6.27% | ||||
Approved interim rate increase | 9.56% | 9.56% | |||
Allowed rate of return on equity | 9.41% | ||||
Rate of return of long term debt in percentage | 47.50% | ||||
Rate of return of equity capital in percentage | 52.50% | ||||
Amount of estimated interim rate refund | $ 5.2 | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Minimum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Decrease in allowed rate of return on rate base | 7.5056% | ||||
Decrease in allowed rate of return on equity | 9.41% | ||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2016 General Rate Case | Maximum | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Decrease in allowed rate of return on rate base | 8.61% | ||||
Decrease in allowed rate of return on equity | 10.74% | ||||
MNDOC | 2016 General Rate Case | Direct Testimony | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 8.87% | ||||
MNDOC | 2016 General Rate Case | Rebuttal Testimony | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 8.66% | ||||
OAG | 2016 General Rate Case | Direct Testimony | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 6.96% | ||||
OAG | 2016 General Rate Case | Rebuttal Testimony | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 7.14% | ||||
ALJ | 2016 General Rate Case | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Percentage of allowed rate of return on equity | 9.54% |
Rate and Regulatory Matters (52
Rate and Regulatory Matters (Detail Textuals 2) - Otter Tail Power Company - North Dakota Public Service Commission - 2010 General Rate Case $ in Millions | Nov. 25, 2009USD ($) |
Public Utilities, General Disclosures [Line Items] | |
Revenue increase approved by rate authority | $ 3.6 |
Percentage of increase in base rate revenue requested | 3.00% |
Percentage of allowed rate of return on rate base | 8.62% |
Percentage of allowed rate of return on equity | 10.75% |
Rate and Regulatory Matters (53
Rate and Regulatory Matters (Detail Textuals 3) - USD ($) | Feb. 12, 2015 | Nov. 06, 2014 | Nov. 12, 2013 | Sep. 28, 2016 | Jun. 30, 2016 | Dec. 22, 2015 | Apr. 21, 2011 | Mar. 31, 2017 | Dec. 31, 2016 |
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory liabilities | $ 88,022,000 | $ 85,727,000 | |||||||
Otter Tail Power Company | South Dakota Public Utilities Commission | 2010 General Rate Case | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Revenue increase approved by rate authority | $ 643,000 | ||||||||
Percentage of increase in base rate revenue requested | 2.32% | ||||||||
Public utilities allowed rate of return on rate base subsequent to approval of increase in base rate | 8.50% | ||||||||
Otter Tail Power Company | Federal Energy Regulatory Commission | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Current return on equity used in transmission rates | 12.38% | 9.70% | 10.32% | ||||||
Proposed reduced return on equity used in transmission rates | 8.67% | 9.15% | |||||||
Additional incentive basis point | 50-basis points | ||||||||
Expected percentage of return on equity | 10.82% | ||||||||
Expected percentage of return on equity, description | ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) | ||||||||
Percentage of refund processed | 90.00% | ||||||||
Regulatory liabilities | $ 1,700,000 | $ 2,700,000 |
Regulatory Assets and Liabili54
Regulatory Assets and Liabilities - Amount of Regulatory Assets and Liabilities Recorded on Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | $ 17,973 | $ 21,297 | |
Regulatory Liabilities - Current | 5,706 | 3,294 | |
Net Regulatory Asset Position - Current | 12,267 | 18,003 | |
Regulatory Assets - Long -Term | 128,968 | 132,094 | |
Regulatory Liabilities - Long -Term | 82,316 | 82,433 | |
Net Regulatory Asset Position - Long-Term | 46,652 | 49,661 | |
Regulatory Assets - Total | 146,941 | 153,391 | |
Regulatory Liabilities - Total | 88,022 | 85,727 | |
Net Regulatory Asset Position | 58,919 | 67,664 | |
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | 6,443 | 6,443 |
Regulatory Assets - Long -Term | [1] | 106,656 | 108,267 |
Regulatory Assets - Total | [1] | $ 113,099 | $ 114,710 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | see below | see below |
Deferred Marked-to-Market Losses | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | $ 4,063 | $ 4,063 |
Regulatory Assets - Long -Term | [1] | 5,452 | 6,467 |
Regulatory Assets - Total | [1] | $ 9,515 | $ 10,530 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 45 months | 48 months |
Conservation Improvement Program Costs and Incentives | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 3,745 | $ 4,836 |
Regulatory Assets - Long -Term | [2] | 5,735 | 5,158 |
Regulatory Assets - Total | [2] | $ 9,480 | $ 9,994 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 30 months | 21 months |
Accumulated ARO Accretion/Depreciation Adjustment | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Assets - Long -Term | [1] | 6,276 | 6,153 |
Regulatory Assets - Total | [1] | $ 6,276 | $ 6,153 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Big Stone II Unrecovered Project Costs - Minnesota | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | $ 739 | $ 778 |
Regulatory Assets - Long -Term | [1] | 1,926 | 2,087 |
Regulatory Assets - Total | [1] | $ 2,665 | $ 2,865 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 49 months | 52 months |
Recoverable Fuel and Purchased Power Costs | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | $ 1,798 | |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 1,798 | |
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | ||
Debt Reacquisition Premiums | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | $ 301 | $ 325 |
Regulatory Assets - Long -Term | [1] | 1,150 | 1,214 |
Regulatory Assets - Total | [1] | $ 1,451 | $ 1,539 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 186 months | 189 months |
Deferred Income Taxes | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | ||
Regulatory Liabilities - Current | |||
Regulatory Assets - Long -Term | [1] | 1,020 | 1,014 |
Regulatory Liabilities - Long -Term | 785 | 818 | |
Regulatory Assets - Total | [1] | 1,020 | 1,014 |
Regulatory Liabilities - Total | $ 785 | $ 818 | |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | asset lives | asset lives |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Minnesota Deferred Rate Case Expenses Subject to Recovery | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [1] | $ 954 | $ 1,082 |
Regulatory Assets - Long -Term | [1] | ||
Regulatory Assets - Total | [1] | $ 954 | $ 1,082 |
Regulatory Assets - Remaining Recovery/Refund Period | [1] | 12 months | 12 months |
North Dakota Renewable Resource Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 727 | $ 1,319 |
Regulatory Assets - Long -Term | [2] | 62 | 482 |
Regulatory Assets - Total | [2] | $ 789 | $ 1,801 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 24 months | 15 months |
Big Stone II Unrecovered Project Costs - South Dakota | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 100 | $ 100 |
Regulatory Assets - Long -Term | [2] | 517 | 543 |
Regulatory Assets - Total | [2] | $ 617 | $ 643 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 74 months | 77 months |
North Dakota Transmission Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 426 | |
Regulatory Assets - Long -Term | [2] | 59 | 568 |
Regulatory Assets - Total | [2] | $ 485 | $ 568 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 21 months | 24 months |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 251 | $ 333 |
Regulatory Liabilities - Current | 33 | ||
Regulatory Assets - Long -Term | [2] | 115 | |
Regulatory Liabilities - Long -Term | 99 | 132 | |
Regulatory Assets - Total | [2] | 366 | 333 |
Regulatory Liabilities - Total | $ 132 | $ 132 | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 21 months | 12 months |
Regulatory Liabilities - Remaining Recovery/Refund Period | 21 months | 24 months | |
South Dakota Transmission Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 106 | $ 73 |
Regulatory Assets - Long -Term | [2] | 141 | |
Regulatory Assets - Total | [2] | $ 106 | $ 214 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 11 months | 14 months |
North Dakota Environmental Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 113 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 113 | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | |
Minnesota Transmission Cost Recovery Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 95 | |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 95 | |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 12 months | |
Minnesota Renewable Resource Rider Accrued Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Assets - Current | [2] | $ 23 | $ 34 |
Regulatory Assets - Long -Term | [2] | ||
Regulatory Assets - Total | [2] | $ 23 | $ 34 |
Regulatory Assets - Remaining Recovery/Refund Period | [2] | 6 months | 9 months |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | |||
Regulatory Liabilities - Long -Term | 81,314 | 80,404 | |
Regulatory Liabilities - Total | $ 81,314 | $ 80,404 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | |
Refundable Fuel Clause Adjustment Revenues | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 2,119 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 2,119 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
North Dakota Transmission Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 1,545 | $ 1,381 | |
Regulatory Liabilities - Long -Term | 782 | ||
Regulatory Liabilities - Total | $ 1,545 | $ 2,163 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 24 months | |
Revenue for Rate Case expenses Subject to Refund - Minnesota | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 711 | $ 711 | |
Regulatory Liabilities - Long -Term | 30 | 208 | |
Regulatory Liabilities - Total | $ 741 | $ 919 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 13 months | 16 months | |
Minnesota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 631 | $ 139 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 631 | $ 139 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
South Dakota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 354 | $ 285 | |
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 354 | $ 285 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 12 months | |
North Dakota Environmental Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 299 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 299 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
South Dakota Transmission Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 8 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 8 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
Minnesota Transmission Cost Recovery Rider Accrued Refund | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 757 | ||
Regulatory Liabilities - Long -Term | |||
Regulatory Liabilities - Total | $ 757 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | ||
Other | |||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||
Regulatory Liabilities - Current | $ 6 | $ 21 | |
Regulatory Liabilities - Long -Term | 88 | 89 | |
Regulatory Liabilities - Total | $ 94 | $ 110 | |
Regulatory Liabilities - Remaining Recovery/Refund Period | 201 months | 204 months | |
[1] | Costs subject to recovery without a rate of return. | ||
[2] | Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Regulatory Assets and Liabili55
Regulatory Assets and Liabilities (Detail Textuals) | 3 Months Ended |
Mar. 31, 2017 | |
Debt Reacquisition Premiums | |
Schedule of Regulatory Assets and Liabilities [Line Items] | |
Regulatory assets - long term, remaining recovery/refund period | 186 months |
Open Contract Positions Subje56
Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details) - Legally enforceable netting arrangements - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items] | ||
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements | ||
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements | (14,590) | (17,382) |
Net Balance Subject to Legally Enforceable Netting Arrangements | $ (14,590) | $ (17,382) |
Open Contract Positions Subje57
Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | |
Current Liability - Marked-to-Market Loss (in thousands) | |||
Loss Contracts Covered by Deposited Funds or Letters of Credit | |||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | [1] | 14,590 | 17,382 |
Total Loss Contracts based on Current Market Values | $ 14,590 | $ 17,382 | |
[1] | Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $14,590 $17,382 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $14,590 $17,382 |
Open Contract Positions Subje58
Open Contract Positions Subject to Legally Enforceable Netting Arrangements - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parentheticals) (Details 1) - Otter Tail Power Company - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 | |
Credit Derivatives [Line Items] | |||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | [1] | $ 14,590 | $ 17,382 |
Offsetting Gains with Counterparties under Master Netting Agreements | |||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $ 14,590 | $ 17,382 | |
[1] | Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP's debt. If OTP's debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions. Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade $14,590 $17,382 Offsetting Gains with Counterparties under Master Netting Agreements 0 0 Reporting Date Deposit Requirement if Credit Risk Feature Triggered $14,590 $17,382 |
Reconciliation of Common Shar59
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, December 31, 2016 | $ 670,104 | |
Common Stock Issuances, Net of Expenses | 2,564 | |
Common Stock Retirements | (1,759) | |
Net Income | 19,585 | $ 14,520 |
Other Comprehensive Income | 105 | |
Employee Stock Incentive Plans Expense | 1,150 | |
Common Dividends ($0.32 per share) | (12,626) | |
Balance, March 31, 2017 | 679,123 | |
Par Value, Common Shares | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, December 31, 2016 | 196,741 | |
Common Stock Issuances, Net of Expenses | 837 | |
Common Stock Retirements | (234) | |
Balance, March 31, 2017 | 197,344 | |
Premium on Common Shares | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, December 31, 2016 | 337,684 | |
Common Stock Issuances, Net of Expenses | 1,727 | |
Common Stock Retirements | (1,525) | |
Employee Stock Incentive Plans Expense | 1,150 | |
Balance, March 31, 2017 | 339,036 | |
Retained Earnings | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, December 31, 2016 | 139,479 | |
Net Income | 19,585 | |
Common Dividends ($0.32 per share) | (12,626) | |
Balance, March 31, 2017 | 146,438 | |
Accumulated Other Comprehensive Income/(Loss) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, December 31, 2016 | (3,800) | |
Other Comprehensive Income | 105 | |
Balance, March 31, 2017 | $ (3,695) |
Reconciliation of Common Shar60
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parentheticals) (Details) - $ / shares | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||
Dividends Declared Per Common Share (in dollars per share) | $ 0.3200 | $ 0.3125 |
Reconciliation of Common Shar61
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1) | 3 Months Ended |
Mar. 31, 2017shares | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |
Common Shares Outstanding, December 31, 2016 | 39,348,136 |
Issuances: | |
Executive Stock Performance Awards (2014 shares earned) | 89,291 |
Automatic Dividend Reinvestment and Share Purchase Plan: | |
Dividends Reinvested | 36,320 |
Cash Invested | 11,750 |
Employee Stock Ownership Plan | 14,835 |
Vesting of Restricted Stock Units | 9,975 |
Employee Stock Purchase Plan: | |
Cash Invested | |
Dividends Reinvested | 5,131 |
Retirements: | |
Shares Withheld for Individual Income Tax Requirements | (46,634) |
Common Shares Outstanding, March 31, 2017 | 39,468,804 |
Reconciliation of Common Shar62
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted (Details 2) - shares | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||
Weighted Average Common Shares Outstanding - Basic | 39,350,802 | 37,936,943 |
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 | 201,639 | 46,885 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 57,873 | 39,841 |
Nonvested Restricted Shares | 27,069 | 17,776 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 3,342 | 3,763 |
Total Dilutive Shares | 289,923 | 108,265 |
Weighted Average Common Shares Outstanding - Diluted | 39,640,725 | 38,045,208 |
Reconciliation of Common Shar63
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | ||
Mar. 31, 2017 | Dec. 31, 2016 | May 11, 2015 | |
Stockholders Equity Note [Line Items] | |||
Maximum per share differences between basic and diluted earnings per share in total or from continuing or discontinued operations | $ 0.01 | $ 0.01 | |
Distribution Agreement | J.P. Morgan Securities (JPMS) | |||
Stockholders Equity Note [Line Items] | |||
Aggregate sales price | $ 75 |
Share-Based Payments - Stock in
Share-Based Payments - Stock incentive awards to executive officers (Details) | 3 Months Ended |
Mar. 31, 2017$ / sharesshares | |
Restricted Stock Units | Through February 6, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 15,900 |
Grant-Date Fair Value per Award | $ / shares | $ 37.65 |
Vesting Percentage | 25.00% |
Vesting Date | February 6, 2021 |
Stock Performance Awards | December 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | shares | 59,500 |
Grant-Date Fair Value per Award | $ / shares | $ 31 |
Vesting Date | December 31, 2019 |
Share-Based Payments - Amounts
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details 1) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | $ 1,150 | $ 1,026 |
Stock Performance Awards | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 649 | 537 |
Restricted Stock Units | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 264 | 245 |
Restricted Stock Units | Non-Executive Employees | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 87 | 64 |
Restricted Stock | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 22 | 29 |
Restricted Stock | Directors | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 128 | 107 |
Employee Stock Purchase Plan | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | $ 44 |
Share-Based Payments - Amount66
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details 1) | 3 Months Ended |
Mar. 31, 2016 | |
Employee Stock Purchase Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock compensation expense, discount rate | 15.00% |
Share-Based Payments (Detail Te
Share-Based Payments (Detail Textuals) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Unrecognized compensation expense related to stock-based compensation | $ | $ 5.3 |
Weighted-average period of amortization | 2 years 3 months 18 days |
Stock Performance Awards | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Targeted aggregate common shares award | 59,500 |
Stock Performance Awards | Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Percentage of target amount as actual payment | 0.00% |
Stock Performance Awards | Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Aggregate common shares award | 89,250 |
Percentage of target amount as actual payment | 150.00% |
Stock Performance Awards | Executive Officers | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Targeted aggregate common shares award total shareholder return component | 39,667 |
Targeted aggregate common shares award return on equity component | 19,833 |
Period specified for average adjusted return | 3 years |
Retained Earnings Restriction (
Retained Earnings Restriction (Detail Textuals) - USD ($) | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Retained Earnings Restriction [Line Items] | ||
Total Capitalization | $ 1,169,495,000 | $ 1,175,445,000 |
OTP | ||
Retained Earnings Restriction [Line Items] | ||
Equity to total capitalization ratio | 52.90% | |
Net assets restricted from distribution | $ 443,000,000 | |
OTP | Minimum | ||
Retained Earnings Restriction [Line Items] | ||
Equity to total capitalization ratio | 47.50% | |
OTP | Maximum | ||
Retained Earnings Restriction [Line Items] | ||
Equity to total capitalization ratio | 58.10% | |
Total Capitalization | $ 1,123,168,000 |
Commitments and Contingencies (
Commitments and Contingencies (Detail Textuals) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017USD ($)Utility | Dec. 31, 2016USD ($) | |
Commitments and Contingencies Disclosure [Line Items] | ||
Loss contingency, range of possible loss, maximum | $ 1 | |
Otter Tail Power Company | ||
Commitments and Contingencies Disclosure [Line Items] | ||
Number of utilities, generators and power marketers | Utility | 200 | |
Otter Tail Power Company | Construction Programs | ||
Commitments and Contingencies Disclosure [Line Items] | ||
Commitment under contracts aggregate amount | $ 114.6 | $ 84.8 |
Otter Tail Power Company | Coal Purchase Commitments | ||
Commitments and Contingencies Disclosure [Line Items] | ||
Commitment under contracts aggregate amount | $ 3 | |
Contracts expiration year | 2019 and 2040 | |
Otter Tail Power Company | Federal Energy Regulatory Commission | ||
Commitments and Contingencies Disclosure [Line Items] | ||
Estimated liability of refund obligation | $ 1.7 | $ 2.7 |
Percentage of refund processed of FERC-ordered reduction in MISO Tariff allowed ROE | 90.00% |
Short-Term and Long-Term Borr70
Short-Term and Long-Term Borrowings - Status of lines of credit (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Line of Credit Facility [Line Items] | ||
Line Limit | $ 300,000 | |
In Use | 59,176 | |
Restricted due to Outstanding Letters of Credit | 50 | |
Available | 240,774 | $ 257,067 |
Otter Tail Corporation Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 130,000 | |
In Use | 12,825 | |
Restricted due to Outstanding Letters of Credit | ||
Available | 117,175 | 130,000 |
OTP Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 170,000 | |
In Use | 46,351 | |
Restricted due to Outstanding Letters of Credit | 50 | |
Available | $ 123,599 | $ 127,067 |
Short-Term and Long-Term Borr71
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Short-Term Debt | $ 59,176 | $ 42,883 |
Long-Term Debt | 537,885 | 540,942 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 45,192 | 33,201 |
Unamortized Long-Term Debt Issuance Costs | 2,321 | 2,400 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 490,372 | 505,341 |
Total Short-Term and Long-Term Debt (with current maturities) | 594,740 | 581,425 |
Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 12,000 | 15,000 |
3.55% Guaranteed Senior Notes, due December 15, 2026 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 80,000 | 80,000 |
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 33,000 | 33,000 |
Senior Unsecured Notes 4.63%, due December 1, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 140,000 | 140,000 |
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 30,000 | 30,000 |
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 42,000 | 42,000 |
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 60,000 | 60,000 |
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 50,000 | 50,000 |
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 90,000 | 90,000 |
North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 86 | 106 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 799 | 836 |
OTP | ||
Debt Instrument [Line Items] | ||
Short-Term Debt | 46,351 | 42,883 |
Long-Term Debt | 445,000 | 445,000 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 32,981 | 32,970 |
Unamortized Long-Term Debt Issuance Costs | 1,801 | 1,861 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 410,218 | 410,169 |
Total Short-Term and Long-Term Debt (with current maturities) | 489,550 | 486,022 |
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 33,000 | 33,000 |
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 140,000 | 140,000 |
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 30,000 | 30,000 |
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 42,000 | 42,000 |
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 60,000 | 60,000 |
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 50,000 | 50,000 |
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 90,000 | 90,000 |
Otter Tail Corporation | ||
Debt Instrument [Line Items] | ||
Short-Term Debt | 12,825 | |
Long-Term Debt | 92,885 | 95,942 |
Less: Current Maturities net of Unamortized Debt Issuance Costs | 12,211 | 231 |
Unamortized Long-Term Debt Issuance Costs | 520 | 539 |
Total Long-Term Debt net of Unamortized Debt Issuance Costs | 80,154 | 95,172 |
Total Short-Term and Long-Term Debt (with current maturities) | 105,190 | 95,403 |
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 12,000 | 15,000 |
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 80,000 | 80,000 |
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 86 | 106 |
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | $ 799 | $ 836 |
Short-Term and Long-Term Borr72
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details 1) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 0.90% | 0.90% |
Long-Term Debt, Due Date | Feb. 5, 2018 | Feb. 5, 2018 |
3.55% Guaranteed Senior Notes, due December 15, 2026 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 3.55% | 3.55% |
Long-Term Debt, Due Date | Dec. 15, 2026 | Dec. 15, 2026 |
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.95% | 5.95% |
Long-Term Debt, Due Date | Aug. 20, 2017 | Aug. 20, 2017 |
Senior Unsecured Notes 4.63%, due December 1, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.63% | 4.63% |
Long-Term Debt, Due Date | Dec. 1, 2021 | Dec. 1, 2021 |
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.15% | 6.15% |
Long-Term Debt, Due Date | Aug. 20, 2022 | Aug. 20, 2022 |
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.37% | 6.37% |
Long-Term Debt, Due Date | Aug. 20, 2027 | Aug. 20, 2027 |
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.68% | 4.68% |
Long-Term Debt, Due Date | Feb. 27, 2029 | Feb. 27, 2029 |
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.47% | 6.47% |
Long-Term Debt, Due Date | Aug. 20, 2037 | Aug. 20, 2037 |
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.47% | 5.47% |
Long-Term Debt, Due Date | Feb. 27, 2044 | Feb. 27, 2044 |
North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 3.95% | 3.95% |
Long-Term Debt, Due Date | Apr. 1, 2018 | Apr. 1, 2018 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 2.54% | 2.54% |
Long-Term Debt, Due Date | Mar. 18, 2021 | Mar. 18, 2021 |
OTP | Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.95% | 5.95% |
Long-Term Debt, Due Date | Aug. 20, 2017 | Aug. 20, 2017 |
OTP | Senior Unsecured Notes 4.63%, due December 1, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.63% | 4.63% |
Long-Term Debt, Due Date | Dec. 1, 2021 | Dec. 1, 2021 |
OTP | Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.15% | 6.15% |
Long-Term Debt, Due Date | Aug. 20, 2022 | Aug. 20, 2022 |
OTP | Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.37% | 6.37% |
Long-Term Debt, Due Date | Aug. 20, 2027 | Aug. 20, 2027 |
OTP | Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.68% | 4.68% |
Long-Term Debt, Due Date | Feb. 27, 2029 | Feb. 27, 2029 |
OTP | Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.47% | 6.47% |
Long-Term Debt, Due Date | Aug. 20, 2037 | Aug. 20, 2037 |
OTP | Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.47% | 5.47% |
Long-Term Debt, Due Date | Feb. 27, 2044 | Feb. 27, 2044 |
Otter Tail Corporation | Term Loan, LIBOR plus 0.90%, due February 5, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 0.90% | 0.90% |
Long-Term Debt, Due Date | Feb. 5, 2018 | Feb. 5, 2018 |
Otter Tail Corporation | 3.55% Guaranteed Senior Notes, due December 15, 2026 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 3.55% | 3.55% |
Long-Term Debt, Due Date | Dec. 15, 2026 | Dec. 15, 2026 |
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 3.95% | 3.95% |
Long-Term Debt, Due Date | Apr. 1, 2018 | Apr. 1, 2018 |
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 2.54% | 2.54% |
Long-Term Debt, Due Date | Mar. 18, 2021 | Mar. 18, 2021 |
Short-Term and Long-Term Borr73
Short-Term and Long-Term Borrowings (Detail Textuals) - Term Loan Agreement - USD ($) $ in Millions | Feb. 05, 2016 | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | |||
Borrowed amount | $ 50 | ||
Interest rate base | 30 day LIBOR plus 0.90% | ||
Description of variable rate basis | LIBOR | ||
Basis spread on variable rate | 0.90% | ||
Repayment of debt | $ 3 | $ 35 |
Pension Plan and Other Postre74
Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost - Benefit Earned During the Period | $ 1,407 | $ 1,382 | |
Interest Cost on Projected Benefit Obligation | 3,534 | 3,522 | |
Expected Return on Assets | (4,807) | (4,867) | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 30 | 47 | |
From Other Comprehensive Income | [1] | 1 | 1 |
Amortization of Net Actuarial Loss: | |||
From Regulatory Asset | 1,273 | 1,227 | |
From Other Comprehensive Income | [1] | 31 | 31 |
Net Periodic Pension Cost | 1,469 | 1,343 | |
Executive Survivor and Supplemental Retirement Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost - Benefit Earned During the Period | 73 | 63 | |
Interest Cost on Projected Benefit Obligation | 422 | 417 | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 4 | 4 | |
From Other Comprehensive Income | [2] | 9 | 9 |
Amortization of Net Actuarial Loss: | |||
From Regulatory Asset | 71 | 73 | |
From Other Comprehensive Income | [3] | 110 | 112 |
Net Periodic Pension Cost | 689 | 678 | |
Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost - Benefit Earned During the Period | 356 | 306 | |
Interest Cost on Projected Benefit Obligation | 678 | 541 | |
Amortization of Prior-Service Cost: | |||
From Regulatory Asset | 33 | ||
From Other Comprehensive Income | [1] | 1 | |
Amortization of Net Actuarial Loss: | |||
From Regulatory Asset | 233 | ||
From Other Comprehensive Income | [1] | 6 | |
Net Periodic Pension Cost | 1,273 | 881 | |
Effect of Medicare Part D Subsidy | $ (140) | $ (257) | |
[1] | Corporate cost included in Other Nonelectric Expenses. | ||
[2] | Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 4 Other Nonelectric Expenses 5 5 | ||
[3] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44 |
Pension Plan and Other Postre75
Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) - Executive Survivor and Supplemental Retirement Plan - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Defined Benefit Plan Disclosure [Line Items] | |||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | [1] | $ 9 | $ 9 |
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | [2] | 110 | 112 |
Electric Operation and Maintenance Expenses | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | 4 | 4 | |
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | 66 | 68 | |
Other Nonelectric Expenses | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | 5 | 5 | |
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | $ 44 | $ 44 | |
[1] | Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 4 $ 4 Other Nonelectric Expenses 5 5 | ||
[2] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 66 $ 68 Other Nonelectric Expenses 44 44 |
Pension Plan and Other Postre76
Pension Plan and Other Postretirement Benefits (Detail Textuals) $ in Millions | 1 Months Ended |
Jan. 31, 2016USD ($) | |
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
Discretionary plan contributions | $ 10 |
Fair Value of Financial Instr77
Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Carrying Amount | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Short-Term Debt | $ (59,176) | $ (42,883) |
Long-Term Debt including Current Maturities | (535,564) | (538,542) |
Fair Value | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Short-Term Debt | (59,176) | (42,883) |
Long-Term Debt including Current Maturities | $ (582,743) | $ (583,835) |
Fair Value of Financial Instr78
Fair Value of Financial Instruments (Detail Textuals) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Otter Tail Corporation Credit Agreement | ||
Fair Value Of Financial Instruments [Line Items] | ||
Line of credit facility, description of variable rate basis | LIBOR | LIBOR |
Basis spread on variable rate | 1.75% | 1.75% |
OTP Credit Agreement | ||
Fair Value Of Financial Instruments [Line Items] | ||
Line of credit facility, description of variable rate basis | LIBOR | LIBOR |
Basis spread on variable rate | 1.25% | 1.25% |
Income Tax Expense - Continui79
Income Tax Expense - Continuing Operations - Effective income tax rate (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Income Before Income Taxes - Continuing Operations | $ 25,892 | $ 19,982 |
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%) | 10,098 | 7,793 |
Increases (Decreases) in Tax from: | ||
Federal Production Tax Credits | (2,052) | (1,686) |
Excess Tax Deduction - 2014 Performance Share Awards | (697) | |
Section 199 Domestic Production Activities Deduction | (330) | (104) |
Corporate Owned Life Insurance | (294) | (92) |
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes | (212) | (212) |
Employee Stock Ownership Plan Dividend Deduction | (172) | (158) |
Other Items - Net | 22 | (49) |
Income Tax Expense - Continuing Operations | $ 6,363 | $ 5,492 |
Effective Income Tax Rate - Continuing Operations | 24.60% | 27.50% |
Income Tax Expense - Continui80
Income Tax Expense - Continuing Operations - Effective income tax rate (Parentheticals) (Details) | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Composite Federal and State Statutory Rate | 39.00% | 39.00% |
Income Tax Expense - Continui81
Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance on January 1 | $ 891 | $ 468 |
Increases Related to Tax Positions for Prior Years | ||
Increases Related to Tax Positions for Current Year | 43 | 16 |
Uncertain Positions Resolved During Year | ||
Balance on March 31 | $ 934 | $ 484 |
Discontinued Operations - Warra
Discontinued Operations - Warranty Reserves (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Movement in Standard Product Warranty Accrual [Roll Forward] | ||
Warranty Reserve Balance, January 1 | $ 1,369 | $ 2,103 |
Additional Provision for Warranties Made During the Year | ||
Settlements Made During the Year | (1) | |
Decrease in Warranty Estimates for Prior Years | (100) | |
Warranty Reserve Balance, March 31 | $ 1,268 | $ 2,103 |
Discontinued Operations (Detail
Discontinued Operations (Detail Textuals) | 3 Months Ended |
Mar. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Warranty period for certain products sold | one to fifteen year warranties |