Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | Apr. 30, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | Otter Tail Corp | |
Entity Central Index Key | 1466593 | |
Trading Symbol | ottr | |
Entity Current Reporting Status | Yes | |
Entity Voluntary Filers | No | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock Shares Outstanding | 37,483,725 | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Amendment Flag | FALSE | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 |
Consolidated_Balance_Sheets_no
Consolidated Balance Sheets (not audited) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Current Assets | ||
Cash and Cash Equivalents | $157 | |
Accounts Receivable: | ||
Trade - Net | 74,071 | 60,172 |
Other | 14,406 | 13,179 |
Inventories | 84,515 | 85,203 |
Deferred Income Taxes | 52,065 | 49,482 |
Unbilled Revenues | 15,199 | 17,996 |
Regulatory Assets | 20,352 | 25,273 |
Other | 6,935 | 7,187 |
Assets of Discontinued Operations | 33,171 | 48,657 |
Total Current Assets | 300,871 | 307,149 |
Investments | 10,405 | 8,582 |
Other Assets | 30,900 | 30,111 |
Goodwill | 31,488 | 31,488 |
Other Intangibles - Net | 11,113 | 11,251 |
Deferred Debits | ||
Unamortized Debt Expense | 4,130 | 4,300 |
Regulatory Assets | 127,368 | 129,868 |
Total Deferred Debits | 131,498 | 134,168 |
Plant | ||
Electric Plant in Service | 1,560,459 | 1,545,112 |
Nonelectric Operations | 178,289 | 175,159 |
Construction Work in Progress | 269,999 | 248,677 |
Total Gross Plant | 2,008,747 | 1,968,948 |
Less Accumulated Depreciation and Amortization | 709,842 | 700,418 |
Net Plant | 1,298,905 | 1,268,530 |
Total Assets | 1,815,180 | 1,791,279 |
Current Liabilities | ||
Short-Term Debt | 48,652 | 10,854 |
Current Maturities of Long-Term Debt | 204 | 201 |
Accounts Payable | 95,876 | 107,013 |
Accrued Salaries and Wages | 12,826 | 19,256 |
Accrued Taxes | 15,342 | 13,793 |
Derivative Liabilities | 11,567 | 14,230 |
Other Accrued Liabilities | 8,890 | 8,793 |
Liabilities of Discontinued Operations | 20,732 | 27,559 |
Total Current Liabilities | 214,089 | 201,699 |
Pensions Benefit Liability | 93,084 | 102,711 |
Other Postretirement Benefits Liability | 54,100 | 53,638 |
Other Noncurrent Liabilities | 24,485 | 26,794 |
Commitments and Contingencies (note 9) | ||
Deferred Credits | ||
Deferred Income Taxes | 239,999 | 230,810 |
Deferred Tax Credits | 25,914 | 26,384 |
Regulatory Liabilities | 77,851 | 77,013 |
Other | 947 | 975 |
Total Deferred Credits | 344,711 | 335,182 |
Capitalization | ||
Long-Term Debt, Net of Current Maturities | 498,437 | 498,489 |
Common Shares, Par Value $5 Per Share - Authorized, 50,000,000 Shares; Outstanding, 2015-37,422,959 Shares; 2014 - 37,218,053 Shares | 187,115 | 186,090 |
Premium on Common Shares | 284,341 | 278,436 |
Retained Earnings | 119,340 | 112,903 |
Accumulated Other Comprehensive Loss | -4,522 | -4,663 |
Total Common Equity | 586,274 | 572,766 |
Total Capitalization | 1,084,711 | 1,071,255 |
Total Liabilities and Equity | 1,815,180 | 1,791,279 |
Cumulative Preferred Shares | ||
Capitalization | ||
Cumulative Shares | ||
Cumulative Preference Shares | ||
Capitalization | ||
Cumulative Shares |
Consolidated_Balance_Sheets_no1
Consolidated Balance Sheets (not audited) (Parentheticals) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
Common shares, par value (in dollars per share) | $5 | $5 |
Common shares, authorized | 50,000,000 | 50,000,000 |
Common shares, outstanding | 37,422,959 | 37,218,053 |
Cumulative Preferred Shares | ||
Cumulative shares, authorized | 1,500,000 | 1,500,000 |
Cumulative shares, without par value (in dollars per share) | ||
Cumulative shares, outstanding | ||
Cumulative Preference Shares | ||
Cumulative shares, authorized | 1,000,000 | 1,000,000 |
Cumulative shares, without par value (in dollars per share) | ||
Cumulative shares, outstanding |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (not audited) (USD $) | 3 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Operating Revenues | ||
Electric | $113,533 | $119,048 |
Product Sales | 89,308 | 95,918 |
Total Operating Revenues | 202,841 | 214,966 |
Operating Expenses | ||
Production Fuel - Electric | 14,599 | 22,030 |
Purchased Power - Electric System Use | 23,692 | 21,785 |
Electric Operation and Maintenance Expenses | 37,527 | 34,622 |
Cost of Products Sold (depreciation included below) | 71,498 | 73,939 |
Other Nonelectric Expenses | 12,463 | 9,951 |
Depreciation and Amortization | 14,535 | 14,267 |
Property Taxes - Electric | 3,502 | 2,971 |
Total Operating Expenses | 177,816 | 179,565 |
Operating Income | 25,025 | 35,401 |
Interest Charges | 7,743 | 6,595 |
Other Income | 572 | 1,535 |
Income Before Income Taxes - Continuing Operations | 17,854 | 30,341 |
Income Tax Expense - Continuing Operations | 4,073 | 8,562 |
Net Income from Continuing Operations | 13,781 | 21,779 |
Discontinued Operations | ||
Loss - net of Income Tax Benefit of $1,376 and $225 for the respective periods | -2,072 | -349 |
Impairment Loss - net of Income Tax Benefit of $0 for the three months ended March 31, 2015 | -1,000 | |
Gain on Disposition - net of Income Tax Expense of $4,816 for the three months ended March 31, 2015 | 7,226 | |
Net Income (Loss) from Discontinued Operations | 4,154 | -349 |
Net Income | $17,935 | $21,430 |
Average Number of Common Shares Outstanding-Basic (in shares) | 37,243,118 | 36,240,350 |
Average Number of Common Shares Outstanding-Diluted (in shares) | 37,497,881 | 36,431,915 |
Basic Earnings (Loss) Per Common Share: | ||
Continuing Operations (in dollars per share) | $0.37 | $0.60 |
Discontinued Operations (in dollars per share) | $0.11 | ($0.01) |
Earnings Per Share, Basic, Total (in dollars per share) | $0.48 | $0.59 |
Diluted Earnings (Loss) Per Common Share: | ||
Continuing Operations (in dollars per share) | $0.37 | $0.60 |
Discontinued Operations (in dollars per share) | $0.11 | ($0.01) |
Earnings Per Share, Diluted, Total (in dollars per share) | $0.48 | $0.59 |
Dividends Declared Per Common Share (in dollars per share) | $0.31 | $0.30 |
Consolidated_Statements_of_Inc1
Consolidated Statements of Income (not audited) (Parentheticals) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Income Statement [Abstract] | ||
Income tax expense (benefit) on income (loss) from discontinued operation | ($1,376) | ($225) |
Income tax (benefit) expense on impairment | 0 | |
Income tax (benefit) expense on gain from disposition | $4,816 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (not audited) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Statement Of Income and Comprehensive Income [Abstract] | ||
Net Income | $17,935 | $21,430 |
Unrealized Gain on Available-for-Sale Securities: | ||
Reversal of Previously Recognized Gains Realized on Sale of Investments and Included in Other Income During Period | -3 | -17 |
Gains (Losses) Arising During Period | 32 | -17 |
Income Tax (Expense) Benefit | -10 | 12 |
Change in Unrealized Gains on Available-for-Sale Securities - net-of-tax | 19 | -22 |
Pension and Postretirement Benefit Plans: | ||
Amortization of Unrecognized Postretirement Benefit Losses and Costs (note 11) | 204 | 50 |
Income Tax (Expense) | -82 | -20 |
Pension and Postretirement Benefit Plans - net-of-tax | 122 | 30 |
Total Other Comprehensive Income | 141 | 8 |
Total Comprehensive Income | $18,076 | $21,438 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (not audited) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Cash Flows from Operating Activities | ||
Net Income | $17,935 | $21,430 |
Adjustments to Reconcile Net Income to Net Cash Used in Operating Activities: | ||
Net Gain from Sale of Discontinued Operations | -7,226 | |
Net Loss from Discontinued Operations | 3,072 | 349 |
Depreciation and Amortization | 14,535 | 14,267 |
Deferred Tax Credits | -470 | -454 |
Deferred Income Taxes | 7,038 | 13,073 |
Change in Deferred Debits and Other Assets | 3,538 | -888 |
Discretionary Contribution to Pension Plan | -10,000 | -20,000 |
Change in Noncurrent Liabilities and Deferred Credits | 41 | -2,408 |
Allowance for Equity/Other Funds Used During Construction | -256 | -340 |
Change in Derivatives Net of Regulatory Deferral | -59 | 118 |
Stock Compensation Expense - Equity Awards | 623 | 358 |
Other - Net | 206 | 182 |
Cash (Used for) Provided by Current Assets and Current Liabilities: | ||
Change in Receivables | -11,288 | -22,329 |
Change in Inventories | 688 | -9,236 |
Change in Other Current Assets | 1,270 | 437 |
Change in Payables and Other Current Liabilities | -20,185 | -7,731 |
Change in Interest and Income Taxes Receivable/Payable | -1,549 | 1,013 |
Net Cash Used in Continuing Operations | -2,087 | -12,159 |
Net Cash Used in Discontinued Operations | -6,263 | -6,898 |
Net Cash Used in Operating Activities | -8,350 | -19,057 |
Cash Flows from Investing Activities | ||
Capital Expenditures | -35,738 | -37,311 |
Net Proceeds from Disposal of Noncurrent Assets | 1,292 | 848 |
Net Increase in Other Investments | -3,492 | -989 |
Net Cash Used in Investing Activities - Continuing Operations | -37,938 | -37,452 |
Net Proceeds from Sale of Discontinued Operations | 21,343 | |
Net Cash (Used in) Provided by Investing Activities - Discontinued Operations | -1,759 | 285 |
Net Cash Used in Investing Activities | -18,354 | -37,167 |
Cash Flows from Financing Activities | ||
Change in Checks Written in Excess of Cash | -1,236 | |
Net Short-Term Borrowings (Repayments) | 37,798 | -39,296 |
Proceeds from Issuance of Common Stock - net of Issuance Expenses | 4,697 | 3,666 |
Payments for Retirement of Capital Stock | -1,239 | -242 |
Proceeds from Issuance of Long-Term Debt | 150,000 | |
Short-Term and Long-Term Debt Issuance Expenses | -4 | -502 |
Payments for Retirement of Long-Term Debt | -49 | -40,946 |
Dividends Paid and Other Distributions | -11,498 | -10,993 |
Net Cash Provided by Financing Activities - Continuing Operations | 28,469 | 61,687 |
Net Cash Used in Financing Activities - Discontinued Operations | -1,178 | |
Net Cash Provided by Financing Activities | 27,291 | 61,687 |
Net Change in Cash and Cash Equivalents - Discontinued Operations | -430 | -126 |
Net Change in Cash and Cash Equivalents | 157 | 5,337 |
Cash and Cash Equivalents at Beginning of Period | 2,007 | |
Cash and Cash Equivalents at End of Period | $157 | $7,344 |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
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, and the price is fixed or determinable. 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. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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. | |||||||||||||||||||||
Warranty Reserves | |||||||||||||||||||||
The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements. | |||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||
The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows: | |||||||||||||||||||||
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (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, 2015 and December 31, 2014: | |||||||||||||||||||||
March 31, 2015 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 381 | |||||||||||||||
Investments: | |||||||||||||||||||||
Money Market Deposit Escrow Account – AEV, Inc. Sale | 2,000 | ||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,625 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,229 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 550 | ||||||||||||||||||||
Total Assets | $ | 2,550 | $ | 7,854 | $ | 381 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | $ | -- | $ | 282 | $ | -- | |||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 11,285 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 282 | $ | 11,285 | |||||||||||||||
December 31, 2014 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 257 | |||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 120 | ||||||||||||||||||||
Investments: | |||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,761 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,253 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 593 | ||||||||||||||||||||
Total Assets | $ | 713 | $ | 8,014 | $ | 257 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | $ | -- | $ | 342 | $ | -- | |||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 13,888 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 342 | $ | 13,888 | |||||||||||||||
The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: | |||||||||||||||||||||
Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods. | |||||||||||||||||||||
Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes. | |||||||||||||||||||||
Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of March 31, 2015 and December 31, 2014, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The March 31, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour. | |||||||||||||||||||||
In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three month periods ended March 31, 2015 and 2014. | |||||||||||||||||||||
The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2015 and 2014: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Forward Energy Contracts - Fair Values Beginning of Period | $ | (13,631 | ) | $ | (11,341 | ) | |||||||||||||||
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods | 3,386 | 1,160 | |||||||||||||||||||
Net Changes in Fair Value of Contracts Entered into in Prior Periods | (368 | ) | 3,498 | ||||||||||||||||||
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period | (10,613 | ) | (6,683 | ) | |||||||||||||||||
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period | (291 | ) | 40 | ||||||||||||||||||
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period | $ | (10,904 | ) | $ | (6,643 | ) | |||||||||||||||
Inventories | |||||||||||||||||||||
Inventories consist of the following: | |||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Finished Goods | $ | 27,607 | $ | 27,998 | |||||||||||||||||
Work in Process | 9,894 | 10,628 | |||||||||||||||||||
Raw Material, Fuel and Supplies | 47,014 | 46,577 | |||||||||||||||||||
Total Inventories | $ | 84,515 | $ | 85,203 | |||||||||||||||||
Goodwill and Other Intangible Assets | |||||||||||||||||||||
An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired. | |||||||||||||||||||||
The following table summarizes changes to goodwill by business segment during 2015: | |||||||||||||||||||||
(in thousands) | Gross Balance | Accumulated Impairments | Balance (net of impairments) | Adjustments to Goodwill in 2015 | Balance (net of impairments) | ||||||||||||||||
December 31, | December 31, | March 31, | |||||||||||||||||||
2014 | 2014 | 2015 | |||||||||||||||||||
Manufacturing | $ | 12,186 | $ | -- | $ | 12,186 | $ | -- | $ | 12,186 | |||||||||||
Plastics | 19,302 | -- | 19,302 | -- | 19,302 | ||||||||||||||||
Total | $ | 31,488 | $ | -- | $ | 31,488 | $ | -- | $ | 31,488 | |||||||||||
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. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014: | |||||||||||||||||||||
March 31, 2015 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying | Remaining | |||||||||||||||||
Amount | Amortization | ||||||||||||||||||||
Periods | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,996 | $ | 10,815 | 57-157 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 447 | 192 | 18 months | |||||||||||||||||
Emission Allowances | 106 | -- | 106 | Expensed as used | |||||||||||||||||
Total | $ | 17,556 | $ | 6,443 | $ | 11,113 | |||||||||||||||
December 31, 2014 (in thousands) | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,784 | $ | 11,027 | 60-160 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 415 | 224 | 21 months | |||||||||||||||||
Total | $ | 17,450 | $ | 6,199 | $ | 11,251 | |||||||||||||||
The amortization expense for these intangible assets was: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Amortization Expense – Intangible Assets | $ | 244 | $ | 244 | |||||||||||||||||
The estimated annual amortization expense for these intangible assets for the next five years is: | |||||||||||||||||||||
(in thousands) | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||
Estimated Amortization Expense – Intangible Assets | $ | 977 | $ | 945 | $ | 849 | $ | 849 | $ | 849 | |||||||||||
The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
(in thousands) | 31-Mar-15 | ||||||||||||||||||||
Emission Allowances Beginning Balance | $ | -- | |||||||||||||||||||
Allowances Purchased | 168 | ||||||||||||||||||||
Allowances Used | (62 | ) | |||||||||||||||||||
Emission Allowances Ending Balance | $ | 106 | |||||||||||||||||||
Supplemental Disclosures of Cash Flow Information | |||||||||||||||||||||
As of March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Noncash Investing Activities: | |||||||||||||||||||||
Accounts Payable Outstanding Related to Capital Additions1 | $ | 32,838 | $ | 22,244 | |||||||||||||||||
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2 | $ | 7,554 | $ | 3,434 | |||||||||||||||||
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. | |||||||||||||||||||||
2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received. | |||||||||||||||||||||
Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements. | |||||||||||||||||||||
Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and 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. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 million. 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, 2015 could be as high as $28.5 million. | |||||||||||||||||||||
New Accounting Standards | |||||||||||||||||||||
ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. | |||||||||||||||||||||
ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. 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. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options. | |||||||||||||||||||||
ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015. | |||||||||||||||||||||
ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements. |
Segment_Information
Segment Information | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Segment Reporting [Abstract] | |||||||||
Segment Information | 2. Segment Information | ||||||||
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. These businesses sell products and provide services to customers primarily in the United States. The three segments are: Electric, Manufacturing and Plastics. | |||||||||
Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is an active wholesale 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 and fabrication, and production of material and handling trays and horticultural containers. These businesses have manufacturing facilities in 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 2014. All of the Company’s long-lived assets are within the United States. | |||||||||
The following table presents the percent of consolidated sales revenue by country: | |||||||||
Three Months Ended March 31, | |||||||||
2015 | 2014 | ||||||||
United States of America | 96.3 | % | 97.2 | % | |||||
Mexico | 3 | % | 2.2 | % | |||||
Canada | 0.6 | % | 0.5 | % | |||||
All Other Countries (none individually greater than 0.05%) | 0.1 | % | 0.1 | % | |||||
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, 2015 and 2014 and total assets by business segment as of March 31, 2015 and December 31, 2014 are presented in the following tables: | |||||||||
Operating Revenue | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 113,547 | $ | 119,088 | |||||
Manufacturing | 56,759 | 55,435 | |||||||
Plastics | 32,552 | 40,483 | |||||||
Intersegment Eliminations | (17 | ) | (40 | ) | |||||
Total | $ | 202,841 | $ | 214,966 | |||||
Interest Charges | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 6,121 | $ | 5,079 | |||||
Manufacturing | 832 | 808 | |||||||
Plastics | 246 | 247 | |||||||
Corporate and Intersegment Eliminations | 544 | 461 | |||||||
Total | $ | 7,743 | $ | 6,595 | |||||
Income Taxes | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 4,221 | $ | 5,750 | |||||
Manufacturing | 504 | 1,671 | |||||||
Plastics | 1,264 | 2,133 | |||||||
Corporate | (1,916 | ) | (992 | ) | |||||
Total | $ | 4,073 | $ | 8,562 | |||||
Net Income | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 13,178 | $ | 16,653 | |||||
Manufacturing | 1,184 | 2,896 | |||||||
Plastics | 2,120 | 3,460 | |||||||
Corporate | (2,701 | ) | (1,230 | ) | |||||
Discontinued Operations | 4,154 | (349 | ) | ||||||
Total | $ | 17,935 | $ | 21,430 | |||||
Identifiable Assets | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 1,484,289 | $ | 1,472,647 | |||||
Manufacturing | 139,143 | 130,701 | |||||||
Plastics | 90,256 | 87,356 | |||||||
Corporate | 68,321 | 51,918 | |||||||
Assets of Discontinued Operations | 33,171 | 48,657 | |||||||
Total | $ | 1,815,180 | $ | 1,791,279 |
Rate_and_Regulatory_Matters
Rate and Regulatory Matters | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Rate and Regulatory Matters [Abstract] | |||||||||
Rate and Regulatory Matters | 3. Rate and Regulatory Matters | ||||||||
Below are descriptions of OTP’s major capital expenditure projects and use of reagents and emission allowances 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 2015 and 2014. | |||||||||
Major Capital Expenditure Projects | |||||||||
Big Stone Plant Air Quality Control System (AQCS)—The South Dakota Department of Environmental and Natural Resources determined that the Big Stone Plant is subject to Best-Available Retrofit Technology (BART) requirements of the Clean Air Act, based on air dispersion modeling indicating that Big Stone Plant’s emissions reasonably contribute to visibility impairment in national parks and wilderness areas in Minnesota, North Dakota, South Dakota and Michigan. | |||||||||
OTP is currently in the final stages of constructing the BART-compliant AQCS at Big Stone Plant for a current projected cost of approximately $384 million (OTP’s 53.9% share would be $207 million) with an expected commercial operation date of October 2015. OTP’s share of AQCS construction expenditures incurred through March 31, 2015 is $174.9 million, excluding Allowance for Funds Used During Construction (AFUDC). | |||||||||
Fargo–Monticello 345 kiloVolt (kV) Capacity Expansion 2020 (CapX2020) Project (the Fargo Project)—The Monticello to St. Cloud portion of the Fargo Project was placed into service on December 21, 2011. The St. Cloud to Alexandria portion of the Fargo Project was placed into service on April 23, 2014. The third and final phase of the Fargo Project, from Alexandria to Fargo, was energized on April 2, 2015. | |||||||||
Brookings–Southeast Twin Cities 345 kV CapX2020 Project (the Brookings Project)—The MISO granted unconditional approval of the Brookings Project as a Multi-Value Project (MVP) under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. The first phase of the 250 mile Brookings Project was energized in March 2014. Additional segments of the line were energized in April 2014. This line was placed into service on March 26, 2015. | |||||||||
The Big Stone South – Brookings MVP and CapX2020 Project—This is a planned 345 kV transmission line that will extend approximately 70 miles between a proposed substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Xcel Energy jointly developed this project. MISO approved this project as an MVP under the MISO Tariff in December 2011. 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 that the costs of transmission projects with regional benefits are properly assigned to those who benefit. A Notice of Intent to Construct Facilities (NICF) was filed with the SDPUC on February 29, 2012. The SDPUC approved the certification for the northern portion of the route on April 9, 2013 and granted approval of a route permit for the southern portion of the line on February 18, 2014. On August 1, 2014 OTP and Xcel Energy entered into agreements to construct the project. This line is expected to be in service in 2017. | |||||||||
The Big Stone South – Ellendale MVP—This is a proposed 345 kV transmission line that will extend 160 to 170 miles between a proposed substation near Big Stone City, South Dakota and a proposed substation near Ellendale, North Dakota. OTP is jointly developing this project with Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (MDU). MISO approved this project as an MVP under the MISO Tariff in December 2011. OTP and MDU jointly filed an NICF with the SDPUC in March of 2012. On August 25, 2013 the NDPSC granted Certificates of Public Convenience and Necessity to OTP and MDU for ten miles of the proposed line to be built in North Dakota. On July 10, 2014 the NDPSC approved a Certificate of Corridor Compatibility and a route permit for the North Dakota section of the proposed line. On August 22, 2014 the SDPUC issued an order approving the route permit for the South Dakota section of the proposed line. If the proposed project receives all the necessary approvals, OTP anticipates the line will be completed in 2019. | |||||||||
Recovery of OTP’s transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders. | |||||||||
Reagent Costs and Emission Allowances | |||||||||
OTP’s system wide costs for reagents and Cross-State Air Pollution Rule (CSAPR) emissions allowances are expected to increase to approximately $4.1 million annually, $3.6 million for reagents and $0.5 million for emission allowances. The Minnesota, North Dakota and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs will be phased in during 2015 and 2016 when the Big Stone Plant AQCS and Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects are completed and in service. Emissions allowance costs are being incurred during 2015 to maintain compliance with CSAPR rules, which became effective January 1, 2015. | |||||||||
Minnesota | |||||||||
2010 General Rate Case—OTP’s most recent general rate increase in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61%, and its allowed rate of return on equity increased from 10.43% to 10.74%. | |||||||||
Minnesota Conservation Improvement Programs (MNCIP)—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On September 26, 2014 the MPUC approved OTP’s 2013 financial incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying charge to be equal to the short term cost of debt set in OTP’s most recent general rate case. Based on results from the 2014 MNCIP program year, OTP now estimates a financial incentive for 2014 of $3.0 million. OTP is estimating a lower incentive for 2014 in response to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07 per kwh saved for 2014-2016. Additionally, OTP estimated it saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation improvement programs in Minnesota. OTP requested approval for recovery of its 2014 MNCIP financial incentive and 2014 program costs not included in base rates from the MPUC in an April 1, 2015 filing. | |||||||||
Transmission Cost Recovery Rider—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs, plus a return on investment at the level approved in a utility’s last general rate case, of new transmission facilities that meet certain criteria. OTP filed its annual update to its Minnesota TCR rider on February 7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but disallowed recovery of capitalized internal costs, costs in excess of Certificate of Need estimates and a carrying charge in the TCR rider. These items were removed from OTP’s Minnesota TCR rider effective March 1, 2014. OTP will be allowed to seek recovery of these costs in a future rate case. In response to the MPUC’s approval of OTP’s annual TCR update, OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014. On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. | |||||||||
Environmental Cost Recovery (ECR) Rider—On December 18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable revenue requirements include a current return on the project’s CWIP balance at the level approved in OTP’s most recent general rate case. OTP filed its 2014 annual update on July 31, 2014, requesting a $4.1 million annual increase in the rider from $6.1 million to $10.2 million. The MPUC approved OTP’s ECR rider annual update request on November 24, 2014, effective December 1, 2014. Because the effective date was two months behind the anticipated implementation date for the updated rate and a portion of the requested increase had been collected under the initial rate, the approved updated rate is based on a revenue requirement of $9.8 million. The rate will continue to be updated in annual filings with the MPUC until the costs are rolled into base rates at an undetermined future date. | |||||||||
Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery of these costs. These costs will be reviewed in OTP’s next general rate case in Minnesota and considered for recovery either through the FCA rider or general rates. | |||||||||
North Dakota | |||||||||
General Rates—OTP’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%. | |||||||||
Renewable Resource Adjustment—OTP has a North Dakota Renewable Resource Adjustment (NDRRA) which enables OTP to recover the North Dakota share of its investments in renewable energy facilities it owns in North Dakota. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed with a return on investment at the level approved in OTP’s most recent general rate case. On December 28, 2012 OTP submitted its annual update to the NDRRA with a proposed effective date of April 1, 2013. The update resulted in a rate reduction, so the NDPSC did not issue an order suspending the rate change. Consequently, pursuant to statute, OTP was allowed to implement updated rates effective April 1, 2013. On July 10, 2013, the NDPSC approved the updated rates implemented on April 1, 2013. The NDPSC approved OTP’s 2013 annual update to the NDRRA on March 12, 2014 with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. OTP submitted its 2014 annual update to the NDRRA on December 31, 2014, which was approved by the NDPSC on March 25, 2015 with an effective date of April 1, 2015. In each instance the NDRRA rates have been based upon a return on investment at the rate of return approved in the OTP’s last general rate case. Approved in the 2014 annual update was a change in rate design from an amount per kwh consumed to a percentage of a customer’s bill. | |||||||||
Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on construction work in progress and a return on investment at the level approved in the utility’s most recent general rate case. On August 30, 2013 OTP filed its annual update to its North Dakota TCR rider rate, which was approved on December 30, 2013 and became effective January 1, 2014. On August 29, 2014 OTP filed its annual update to the North Dakota TCR rider rate. Within this TCR filing, as required by the order for the North Dakota Big Stone II rider, OTP included the over-collection of North Dakota Big Stone II abandoned plant costs of $0.1 million. The NDPSC approved the annual update on December 17, 2014 with an effective date of January 1, 2015. | |||||||||
Environmental Cost Recovery Rider—On May 9, 2012 the NDPSC approved OTP’s application for an ADP related to the Big Stone Plant AQCS. On February 8, 2013 OTP filed a request with the NDPSC for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS. On December 18, 2013 the NDPSC approved OTP’s North Dakota ECR rider based on revenue requirements through the 2013 calendar year and thereafter, with rates effective for bills rendered on or after January 1, 2014. The ECR provides for a current return on construction work in progress and a return on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed its annual update to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531% of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation date. On March 31, 2015 OTP filed its annual update to the ECR with a proposed implementation date of July 1, 2015. | |||||||||
Reagent Costs and Emission Allowances—On July 31, 2014 OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance costs. On February 25, 2015 the NDPSC approved recovery of these costs through the modification of the ECR rider to add a new variable monthly reagent and emissions allowance charge effective May 1, 2015. | |||||||||
South Dakota | |||||||||
2010 General Rate Case—On April 21, 2011, the SDPUC issued a written order approving an overall revenue increase for OTP of approximately $643,000 (2.32%) and an overall rate of return on rate base of 8.50%. Final rates were effective with bills rendered on and after June 1, 2011. | |||||||||
Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. The SDPUC approved an annual update to OTP’s South Dakota TCR on April 23, 2013 with an effective date of May 1, 2013. The SDPUC approved OTP’s following annual update on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s most recent annual update on February 13, 2015 with an effective date of March 1, 2015. | |||||||||
Environmental Cost Recovery Rider—On November 25, 2014 the SDPUC approved OTP’s ECR rider request to recover OTP’s jurisdictional share of costs and provide a return on investment for the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December 1, 2014. | |||||||||
Reagent Costs and Emission Allowances—On August 1, 2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA rider. | |||||||||
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, 2015 and 2014: | |||||||||
Three Months Ended March 31, | |||||||||
Rate Rider (in thousands) | 2015 | 2014 | |||||||
Minnesota | |||||||||
Conservation Improvement Program Costs and Incentives1 | $ | 1,928 | $ | 1,521 | |||||
Transmission Cost Recovery | 1,615 | 2,304 | |||||||
Environmental Cost Recovery | 2,557 | 1,763 | |||||||
North Dakota | |||||||||
Renewable Resource Adjustment | 1,883 | 1,435 | |||||||
Transmission Cost Recovery | 1,936 | 1,514 | |||||||
Environmental Cost Recovery | 2,156 | 1,522 | |||||||
Big Stone II Project Costs | -- | 361 | |||||||
South Dakota | |||||||||
Transmission Cost Recovery | 363 | 346 | |||||||
Environmental Cost Recovery | 504 | -- | |||||||
1Includes MNCIP costs recovered in base rates. | |||||||||
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 October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing. | |||||||||
On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the return on equity (ROE) component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants are seeking to reduce the current 12.38% return on equity used in MISO’s transmission rates to a proposed 9.15%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. On October 16, 2014 the FERC issued an order finding that the current MISO return on equity may be unjust and unreasonable and setting the issue for hearing, subject to the outcome of settlement discussion. Settlement discussions did not resolve the dispute and the FERC set the proceeding to a Track II Hearing for complex cases that can take several months to decide with a FERC decision anticipated in fall 2016 at the earliest. 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 resolution of the return on equity complaint proceeding. | |||||||||
On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the return on equity component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from the current 12.38% to a proposed 8.67%. A group of MISO transmission owners have filed responses to the complaint, defending the current return on equity and seeking dismissal of the complaint. As of April 30, 2015, the FERC had not responded to the complaint. | |||||||||
In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff. |
Regulatory_Assets_and_Liabilit
Regulatory Assets and Liabilities | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
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 (ASC 980). This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets: | ||||||||||||||
31-Mar-15 | Remaining | |||||||||||||
Recovery/ | ||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period | ||||||||||
Regulatory Assets: | ||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 7,465 | $ | 99,659 | $ | 107,124 | see below | |||||||
Deferred Marked-to-Market Losses1 | 2,059 | 9,226 | 11,285 | 69 months | ||||||||||
Conservation Improvement Program Costs and Incentives2 | 3,815 | 3,511 | 7,326 | 27 months | ||||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | -- | 5,305 | 5,305 | asset lives | ||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 2,152 | 1,835 | 3,987 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 601 | 3,086 | 3,687 | 93 months | ||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 2,140 | 636 | 2,776 | 24 months | ||||||||||
Debt Reacquisition Premiums1 | 351 | 1,802 | 2,153 | 210 months | ||||||||||
Deferred Income Taxes1 | -- | 1,461 | 1,461 | asset lives | ||||||||||
Recoverable Fuel and Purchased Power Costs1 | 1,249 | -- | 1,249 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – South Dakota2 | 100 | 718 | 818 | 98 months | ||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Revenues2 | 420 | -- | 420 | 12 months | ||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | -- | 68 | 68 | see below | ||||||||||
North Dakota Renewable Resource Rider Accrued Revenues2 | -- | 61 | 61 | 12 months | ||||||||||
Total Regulatory Assets | $ | 20,352 | $ | 127,368 | $ | 147,720 | ||||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | $ | -- | $ | 75,220 | $ | 75,220 | asset lives | |||||||
North Dakota Renewable Resource Rider Accrued Refund | 1,803 | -- | 1,803 | 12 months | ||||||||||
Deferred Income Taxes | -- | 1,447 | 1,447 | asset lives | ||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | -- | 908 | 908 | see below | ||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Refund | 451 | -- | 451 | 12 months | ||||||||||
Deferred Marked-to-Market Gains | 204 | 177 | 381 | 58 months | ||||||||||
Big Stone II Over Recovered Project Costs – North Dakota | 111 | -- | 111 | 9 months | ||||||||||
Deferred Gain on Sale of Utility Property – Minnesota Portion | 6 | 99 | 105 | 225 months | ||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Refund | 86 | -- | 86 | 12 months | ||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 48 | -- | 48 | 12 months | ||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Refund | 35 | -- | 35 | 12 months | ||||||||||
Total Regulatory Liabilities | $ | 2,744 | $ | 77,851 | $ | 80,595 | ||||||||
Net Regulatory Asset Position | $ | 17,608 | $ | 49,517 | $ | 67,125 | ||||||||
1Costs subject to recovery without a rate of return. | ||||||||||||||
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. | ||||||||||||||
31-Dec-14 | Remaining | |||||||||||||
Recovery/ | ||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period | ||||||||||
Regulatory Assets: | ||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 7,464 | $ | 101,526 | $ | 108,990 | see below | |||||||
Deferred Marked-to-Market Losses1 | 4,492 | 9,396 | 13,888 | 72 months | ||||||||||
Conservation Improvement Program Costs and Incentives2 | 5,843 | 2,500 | 8,343 | 18 months | ||||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | -- | 5,190 | 5,190 | asset lives | ||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 592 | 3,207 | 3,799 | 96 months | ||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 943 | 2,455 | 3,398 | 24 months | ||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 2,585 | 807 | 3,392 | 24 months | ||||||||||
Debt Reacquisition Premiums1 | 351 | 1,890 | 2,241 | 213 months | ||||||||||
Deferred Income Taxes1 | -- | 2,086 | 2,086 | asset lives | ||||||||||
Recoverable Fuel and Purchased Power Costs1 | 1,114 | -- | 1,114 | 12 months | ||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Revenues2 | 859 | -- | 859 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – South Dakota2 | 100 | 743 | 843 | 101 months | ||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Revenues2 | 706 | -- | 706 | 12 months | ||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 186 | -- | 186 | 12 months | ||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | -- | 68 | 68 | see below | ||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Revenues2 | 38 | -- | 38 | 12 months | ||||||||||
Total Regulatory Assets | $ | 25,273 | $ | 129,868 | $ | 155,141 | ||||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | $ | -- | $ | 74,237 | $ | 74,237 | asset lives | |||||||
Deferred Income Taxes | -- | 1,550 | 1,550 | asset lives | ||||||||||
North Dakota Renewable Resource Rider Accrued Refund | 933 | 85 | 1,018 | 15 months | ||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | -- | 784 | 784 | see below | ||||||||||
Deferred Marked-to-Market Gains | -- | 257 | 257 | 67 months | ||||||||||
Big Stone II Over Recovered Project Costs – North Dakota | 147 | -- | 147 | 12 months | ||||||||||
Deferred Gain on Sale of Utility Property – Minnesota Portion | 6 | 100 | 106 | 228 months | ||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 48 | -- | 48 | 12 months | ||||||||||
South Dakota – Nonasset-Based Margin Sharing Excess | 24 | -- | 24 | 12 months | ||||||||||
Total Regulatory Liabilities | $ | 1,158 | $ | 77,013 | $ | 78,171 | ||||||||
Net Regulatory Asset Position | $ | 24,115 | $ | 52,855 | $ | 76,970 | ||||||||
1Costs subject to recovery without a rate of return. | ||||||||||||||
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. | ||||||||||||||
The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715, Compensation—Retirement Benefits, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates. | ||||||||||||||
All Deferred Marked-to-Market Gains and Losses recorded as of March 31, 2015 are related 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. | ||||||||||||||
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, 2015. | ||||||||||||||
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 generation project. | ||||||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up relates to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-up also includes 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. | ||||||||||||||
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 210 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. | ||||||||||||||
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 generation project. | ||||||||||||||
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, 2015. | ||||||||||||||
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 MNRRA rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered in OTP’s next general rate case. | ||||||||||||||
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, 2015. | ||||||||||||||
The Accumulated Reserve for Estimated Removal Costs – Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred. | ||||||||||||||
The North Dakota Renewable Resource Rider Accrued Refund relates to amounts collected for qualifying renewable resource costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of March 31, 2015. | ||||||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota relate 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. | ||||||||||||||
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, 2015. | ||||||||||||||
Big Stone II Over Recovered Project Costs – North Dakota represent amounts collected from North Dakota customers in excess of the North Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II generation project. | ||||||||||||||
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, 2015. | ||||||||||||||
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, 2015. | ||||||||||||||
The North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investment in the Big Stone Plant AQCS project that are refundable to North Dakota customers as of March 31, 2015. | ||||||||||||||
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 extraordinary expense or income item in the period in which the application of guidance under ASC 980 ceases. | ||||||||||||||
Forward_Contracts_Classified_a
Forward Contracts Classified as Derivatives | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||
Forward Contracts Classified as Derivatives | 5. Forward Contracts Classified as Derivatives | ||||||||
Electricity Contracts | |||||||||
All of OTP’s wholesale purchases and sales of energy under forward contracts that do not meet the definition of capacity contracts are considered derivatives subject to mark-to-market accounting. OTP’s objective in entering into forward contracts for the purchase and sale of energy is to meet the energy requirements of its retail customers and to optimize the use of its generating and transmission facilities. OTP’s intent in entering into certain of these contracts is to settle them through the physical delivery of energy when physically possible and economically feasible. Prior to December 2014, OTP also entered into certain contracts for trading purposes with the intent to profit from fluctuations in market prices through the timing of purchases and sales. Effective December 31, 2014 OTP discontinued its trading activities not directly associated with serving retail customers. | |||||||||
OTP’s forward contracts outstanding as of March 31, 2015 and December 31, 2014 for the purchase of electricity are scheduled for delivery at the OTP node, which is an illiquid trading point. Prices used to value OTP’s forward purchases at this trading point were based on a basis spread between the OTP node and more liquid trading hub prices. These basis spreads were determined based on available market price information and the use of forward price curve models. The fair value measurements of these forward energy contracts fall into Level 3 of the fair value hierarchy set forth in ASC 820. | |||||||||
The following tables show the effect of marking to market OTP’s forward contracts for the purchase of electricity and the location and fair value amounts of the related derivatives reported on the Company’s consolidated balance sheets as of March 31, 2015 and December 31, 2014, and the change in the Company’s consolidated balance sheet position from December 31, 2014 to March 31, 2015 and December 31, 2013 to March 31, 2014: | |||||||||
(in thousands) | 31-Mar-15 | 31-Dec-14 | |||||||
Current Asset – Marked-to-Market Gain | $ | 381 | $ | 257 | |||||
Regulatory Asset – Current Deferred Marked-to-Market Loss | 2,059 | 4,492 | |||||||
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss | 9,226 | 9,396 | |||||||
Total Assets | 11,666 | 14,145 | |||||||
Current Liability – Marked-to-Market Loss | (11,285 | ) | (13,888 | ) | |||||
Regulatory Liability – Current Deferred Marked-to-Market Gain | (204 | ) | -- | ||||||
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain | (177 | ) | (257 | ) | |||||
Total Liabilities | (11,666 | ) | (14,145 | ) | |||||
Net Fair Value of Marked-to-Market Energy Contracts | $ | -- | $ | -- | |||||
(in thousands) | Year-to-Date | Year-to-Date | |||||||
31-Mar-15 | 31-Mar-14 | ||||||||
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year | $ | -- | $ | 115 | |||||
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods | -- | (72 | ) | ||||||
Changes in Fair Value of Contracts Entered into in Prior Periods | -- | (43 | ) | ||||||
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period | -- | -- | |||||||
Changes in Fair Value of Contracts Entered into in Current Period | -- | 39 | |||||||
Cumulative Fair Value Adjustments Included in Earnings - End of Period | $ | -- | $ | 39 | |||||
The following realized and unrealized net loss on forward energy contracts is included in electric operating revenues on the Company’s consolidated statements of income: | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Net Loss on Forward Electric Energy Contracts | $ | -- | $ | (4 | ) | ||||
OTP has established guidelines and limits to manage credit risk associated with wholesale power and capacity purchases and sales. Specific limits are determined by a counterparty’s financial strength. Counterparties with investment grade credit ratings have minimum credit ratings of BBB- (Standard & Poor’s), Baa3 (Moody’s) or BBB- (Fitch). OTP had no exposure at March 31, 2015 to counterparties with investment grade or below investment grade credit ratings with respect to any of its forward energy contracts. | |||||||||
Individual counterparty exposures for certain contracts can be offset according to legally enforceable netting arrangements. However, the Company does not net offsetting payables and receivables or derivative assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet. The amounts of derivative asset and derivative liability balances that were subject to legally enforceable netting arrangements as of March 31, 2015 and December 31, 2014 are indicated in the following table: | |||||||||
(in thousands) | 31-Mar-15 | 31-Dec-14 | |||||||
Derivative assets subject to legally enforceable netting arrangements | $ | 381 | $ | 257 | |||||
Derivative liabilities subject to legally enforceable netting arrangements | (11,567 | ) | (14,230 | ) | |||||
Net balance subject to legally enforceable netting arrangements | $ | (11,186 | ) | $ | (13,973 | ) | |||
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, 2015 and December 31, 2014: | |||||||||
Current Liability – Marked-to-Market Loss (in thousands) | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Loss Contracts Covered by Deposited Funds or Letters of Credit | $ | 282 | $ | 45 | |||||
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1 | 11,285 | 13,888 | |||||||
Loss Contracts with No Ratings Triggers or Deposit Requirements | -- | 297 | |||||||
Total Current Liability – Marked-to-Market Loss | $ | 11,567 | $ | 14,230 | |||||
1Certain 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 | $ | 11,285 | $ | 13,888 | |||||
Offsetting Gains with Counterparties under Master Netting Agreements | (381 | ) | (257 | ) | |||||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $ | 10,904 | $ | 13,631 |
Reconciliation_of_Common_Share
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
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 | ||||||||||||||||
Common | on | Earnings | Other | Common | |||||||||||||||||
Shares | Common | Comprehensive | Equity | ||||||||||||||||||
Shares | Income/(Loss) | ||||||||||||||||||||
Balance, December 31, 2014 | $ | 186,090 | $ | 278,436 | $ | 112,903 | $ | (4,663 | ) | $ | 572,766 | ||||||||||
Common Stock Issuances, Net of Expenses | 1,220 | 6,302 | 7,522 | ||||||||||||||||||
Common Stock Retirements | (195 | ) | (1,044 | ) | (1,239 | ) | |||||||||||||||
Net Income | 17,935 | 17,935 | |||||||||||||||||||
Other Comprehensive Income | 141 | 141 | |||||||||||||||||||
Tax Benefit – Stock Compensation | 24 | 24 | |||||||||||||||||||
Employee Stock Incentive Plans Expense | 623 | 623 | |||||||||||||||||||
Common Dividends ($0.3075 per share) | (11,498 | ) | (11,498 | ) | |||||||||||||||||
Balance, March 31, 2015 | $ | 187,115 | $ | 284,341 | $ | 119,340 | $ | (4,522 | ) | $ | 586,274 | ||||||||||
Shelf Registration | |||||||||||||||||||||
The Company’s shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) on May 11, 2012, 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 10, 2015. On May 14, 2012, 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, 2014 through March 31, 2015: | |||||||||||||||||||||
Common Shares Outstanding, December 31, 2014 | 37,218,053 | ||||||||||||||||||||
Issuances: | |||||||||||||||||||||
Executive Stock Performance Awards (2012-2014 shares earned) | 89,991 | ||||||||||||||||||||
Automatic Dividend Reinvestment and Share Purchase Plan: | |||||||||||||||||||||
Dividends Reinvested | 42,518 | ||||||||||||||||||||
Cash Invested | 16,553 | ||||||||||||||||||||
At-the-Market Offering | 38,160 | ||||||||||||||||||||
Employee Stock Purchase Plan: | |||||||||||||||||||||
Cash Invested | 19,993 | ||||||||||||||||||||
Dividends Reinvested | 5,985 | ||||||||||||||||||||
Employee Stock Ownership Plan | 21,137 | ||||||||||||||||||||
Stock Options Exercised | 9,000 | ||||||||||||||||||||
Vesting of Restricted Stock Units | 700 | ||||||||||||||||||||
Retirements: | |||||||||||||||||||||
Shares Withheld for Individual Income Tax Requirements | (39,131 | ) | |||||||||||||||||||
Common Shares Outstanding, March 31, 2015 | 37,422,959 | ||||||||||||||||||||
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, 2015 and 2014. 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 of Weighted Average Common Shares Outstanding – Basic to Weighted Average Common Shares Outstanding – Diluted for the three month periods ended March 31: | |||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||
Weighted Average Common Shares Outstanding – Basic | 37,243,118 | 36,240,350 | |||||||||||||||||||
Plus: | |||||||||||||||||||||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers | 229,100 | 131,000 | |||||||||||||||||||
Nonvested Restricted Shares | 83,330 | 90,798 | |||||||||||||||||||
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 70,900 | 55,655 | |||||||||||||||||||
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 40,462 | 39,197 | |||||||||||||||||||
Potentially Dilutive Stock Options | 3,750 | 18,050 | |||||||||||||||||||
Less: | |||||||||||||||||||||
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares | (169,842 | ) | (127,709 | ) | |||||||||||||||||
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options | (2,937 | ) | (15,426 | ) | |||||||||||||||||
Total Dilutive Shares | 254,763 | 191,565 | |||||||||||||||||||
Weighted Average Common Shares Outstanding – Diluted | 37,497,881 | 36,431,915 | |||||||||||||||||||
The effect of dilutive shares on earnings per share for the three month periods ended March 31, 2015 and 2014, 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. |
ShareBased_Payments
Share-Based Payments | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | ||||||||||
Share-Based Payments | 7. Share-Based Payments | |||||||||
Stock Incentive Awards | ||||||||||
On February 6, 2015 the Company’s Board of Directors granted the following stock incentive awards to the Company’s executive officers under the 2014 Stock Incentive Plan. | ||||||||||
Award | Shares/Units | Weighted | Vesting | |||||||
Granted | Average | |||||||||
Grant-Date | ||||||||||
Fair Value | ||||||||||
per Award | ||||||||||
Stock Performance Awards Granted to Executive Officers | 77,500 | $ | 26.99 | 31-Dec-17 | ||||||
Restricted Stock Units Granted to Executive Officers: | ||||||||||
Graded Vesting | 20,900 | $ | 31.675 | 25% per year through February 6, 2019 | ||||||
Cliff Vesting | 6,400 | $ | 31.675 | 100% on February 6, 2020 | ||||||
Under the performance share awards the aggregate award for performance at target is 77,500 shares. For target performance the Company’s executive officers would earn an aggregate of 51,667 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, 2015 through December 31, 2017. The Company’s executive officers would also earn an aggregate of 25,833 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 116,250 common shares. The executive officers have no voting or dividend rights related to these shares until the shares, if any, are issued at the end of the performance period. The terms of these awards are such that the entire award will be classified and accounted for as a liability, as required under ASC Topic 718, Compensation–Stock Compensation, and will be measured over the performance period based on the fair value of the award at the end of each reporting period subsequent to the grant date. | ||||||||||
Under the 2015 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 vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement or, 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. | ||||||||||
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, 2015 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $2.8 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, 2015 and 2014 are presented in the table below: | ||||||||||
Three months ended | ||||||||||
March 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Employee Stock Purchase Plan (15% discount) | $ | 49 | $ | 42 | ||||||
Restricted Stock Granted to Directors | 98 | 123 | ||||||||
Restricted Stock Granted to Executive Officers | 157 | 135 | ||||||||
Restricted Stock Units Granted to Non-Executive Employees | 66 | 58 | ||||||||
Restricted Stock Units Granted to Executive Officers | 253 | -- | ||||||||
Stock Performance Awards Granted to Executive Officers | 1,020 | 526 | ||||||||
Totals | $ | 1,643 | $ | 884 |
Retained_Earnings_Restriction
Retained Earnings Restriction | 3 Months Ended |
Mar. 31, 2015 | |
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 credit agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of March 31, 2015 the Company was in compliance with the debt covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2014 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, 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 45.0% and 55.0%. OTP’s equity to total capitalization ratio including short-term debt was 50.7% as of March 31, 2015. Total capitalization for OTP cannot currently exceed $987 million. |
Commitments_and_Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 9. Commitments and Contingencies |
Construction and Other Purchase Commitments | |
At December 31, 2014 OTP had commitments under contracts in connection with construction programs extending into 2018 of approximately $106.6 million. At March 31, 2015 OTP had commitments under contracts in connection with construction programs extending into 2018 aggregating approximately $106.1 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 2039. In the first quarter of 2015, OTP entered into an energy purchase agreement for the purchase of electricity in April, May and June of 2015 to make up for reduced generation from Coyote Station as it continues to make repairs related to damage caused by a boiler feed pump failure and ensuing fire in December 2014. The total cost for the replacement power will be approximately $2.9 million. | |
OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP’s current coal purchase agreements, under which OTP is committed to the minimum purchase amounts or to make payments in lieu thereof, expire in 2015, 2016, 2017 and 2040. In the first quarter of 2015, OTP entered into a second contract for the purchase of Wyoming subbituminous coal to meet a portion of its 2015 through 2017 coal requirements at Big Stone Plant. OTP’s share of the purchase commitment under this contract as of March 31, 2015 is approximately $10.0 million. Fuel clause adjustment mechanisms lessen the risk of loss from market price changes because they provide for recovery of most fuel costs. | |
Operating Leases | |
In April of 2015, OTP entered into an agreement to extend the term of its lease of rail cars used for the transport of coal to Hoot Lake Plant by 36 months beginning April 1, 2015, for a total commitment of approximately $2.8 million. | |
Contingencies | |
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 $5.0 million. | |
In the first quarter of 2015, OTP recorded a $0.6 million liability representing its current best estimate of a refund obligation, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a potential reduction by FERC in the ROE component of the MISO Tariff. | |
On June 21, 2010 the EPA published a proposed rule that outlines two possible options to regulate disposal of coal ash generated from the combustion of coal by electric utilities under the Resource Conservation and Recovery Act (RCRA). In one option, the EPA would propose to list coal ash destined for disposal in landfills or surface impoundments as “special wastes” subject to regulation under Subtitle C of RCRA. Subtitle C regulations set forth the EPA’s hazardous waste regulatory program, which regulates the generation, handling, transport and disposal of wastes. Under the other proposed regulatory option, the EPA would regulate the disposal of coal ash under Subtitle D of RCRA, the regulatory program for nonhazardous solid wastes. On December 19, 2014 the EPA announced a final rule following the Subtitle D nonhazardous provisions. Publication of the final rule on April 17, 2015 opened a 90-day window within which petitions for judicial review may be filed in the D.C. Circuit. Challenges by environmental groups are possible and the outcome of such challenges cannot be predicted. Thus, uncertainty regarding the status of this rule is likely to continue for a period of time. The rule requires OTP to complete certain actions, such as installing additional groundwater monitoring wells and investigating whether existing surface impoundments meet defined location restrictions, in order to determine whether existing surface impoundments should be retired or retrofitted with liners. The cost impact of this rule will not be known until those actions are completed. As of the date of this report on From 10-Q, OTP had not completed its assessment under the final rule nor made a determination if compliance with the rule would require immediate remediation or result in the recognition of additional AROs beyond those already recognized by OTP in connection with its active and inactive ash disposal sites. Existing landfill cells can continue to operate as designed, but future expansions will require composite liner and leachate collection systems. The EPA is also considering future regulation of coal ash under Subtitle C. | |
Other | |
The Company is a party to litigation 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, 2015 will not be material. |
ShortTerm_and_LongTerm_Borrowi
Short-Term and Long-Term Borrowings | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
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, 2015 and December 31, 2014: | |||||||||||||||||||||
(in thousands) | Line Limit | In Use on | Restricted due to | Available on | Available on | ||||||||||||||||
31-Mar-15 | Outstanding | March 31, | December 31, | ||||||||||||||||||
Letters of Credit | 2015 | 2014 | |||||||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 150,000 | $ | 40,846 | $ | 195 | $ | 108,959 | $ | 138,872 | |||||||||||
OTP Credit Agreement | 170,000 | 7,806 | 560 | 161,634 | 169,440 | ||||||||||||||||
Total | $ | 320,000 | $ | 48,652 | $ | 755 | $ | 270,593 | $ | 308,312 | |||||||||||
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, 2015 and December 31, 2014: | |||||||||||||||||||||
March 31, 2015 (in thousands) | OTP | Otter Tail | Otter Tail | ||||||||||||||||||
Corporation | Corporation | ||||||||||||||||||||
Consolidated | |||||||||||||||||||||
Short-Term Debt | $ | 7,806 | $ | 40,846 | $ | 48,652 | |||||||||||||||
Long-Term Debt: | |||||||||||||||||||||
9.000% Notes, due December 15, 2016 | $ | 52,330 | 52,330 | ||||||||||||||||||
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 | -- | 237 | 237 | ||||||||||||||||||
Partnership in Assisting Community Expansion (PACE) Note, | -- | 1,074 | 1,074 | ||||||||||||||||||
2.54%, due March 18, 2021 | |||||||||||||||||||||
Total | $ | 445,000 | $ | 53,641 | $ | 498,641 | |||||||||||||||
Less: Current Maturities | -- | 204 | 204 | ||||||||||||||||||
Total Long-Term Debt | $ | 445,000 | $ | 53,437 | $ | 498,437 | |||||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 452,806 | $ | 94,487 | $ | 547,293 | |||||||||||||||
December 31, 2014 (in thousands) | OTP | Otter Tail | Otter Tail | ||||||||||||||||||
Corporation | Corporation | ||||||||||||||||||||
Consolidated | |||||||||||||||||||||
Short-Term Debt | $ | -- | $ | 10,854 | $ | 10,854 | |||||||||||||||
Long-Term Debt: | |||||||||||||||||||||
9.000% Notes, due December 15, 2016 | $ | 52,330 | $ | 52,330 | |||||||||||||||||
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 | -- | 256 | 256 | ||||||||||||||||||
Partnership in Assisting Community Expansion (PACE) Note, | -- | 1,105 | 1,105 | ||||||||||||||||||
2.54%, due March 18, 2021 | |||||||||||||||||||||
Total | $ | 445,000 | $ | 53,691 | $ | 498,691 | |||||||||||||||
Less: Current Maturities | -- | 201 | 201 | ||||||||||||||||||
Unamortized Debt Discount | -- | 1 | 1 | ||||||||||||||||||
Total Long-Term Debt | $ | 445,000 | $ | 53,489 | $ | 498,489 | |||||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 445,000 | $ | 64,544 | $ | 509,544 |
Pension_Plan_and_Other_Postret
Pension Plan and Other Postretirement Benefits | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Compensation and Retirement Disclosure [Abstract] | |||||||||
Pension Plan and Other Postretirement Benefits | 11. Pension Plan and Other Postretirement Benefits | ||||||||
Pension Plan—Components of net periodic pension benefit cost of the Company’s noncontributory funded pension plan are as follows: | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 1,500 | $ | 1,175 | |||||
Interest Cost on Projected Benefit Obligation | 3,325 | 3,285 | |||||||
Expected Return on Assets | (4,600 | ) | (4,187 | ) | |||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 47 | 64 | |||||||
From Other Comprehensive Income1 | 1 | 2 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 1,633 | 868 | |||||||
From Other Comprehensive Income1 | 40 | 23 | |||||||
Net Periodic Pension Cost | $ | 1,946 | $ | 1,230 | |||||
1Corporate cost included in Other Nonelectric Expenses. | |||||||||
Cash flows—The Company made discretionary plan contributions totaling $10,000,000 in January 2015. The Company currently is not required and does not expect to make an additional contribution to the plan in 2015. The Company also made discretionary plan contributions totaling $20,000,000 in January 2014. | |||||||||
Executive Survivor and Supplemental Retirement Plan—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows: | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 47 | $ | 13 | |||||
Interest Cost on Projected Benefit Obligation | 381 | 380 | |||||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 4 | 5 | |||||||
From Other Comprehensive Income1 | 10 | 13 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 83 | 35 | |||||||
From Other Comprehensive Income2 | 151 | 12 | |||||||
Net Periodic Pension Cost | $ | 676 | $ | 458 | |||||
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | |||||||||
Electric Operation and Maintenance Expenses | $ | 4 | $ | 5 | |||||
Other Nonelectric Expenses | 6 | 8 | |||||||
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | |||||||||
Electric Operation and Maintenance Expenses | $ | 78 | $ | 33 | |||||
Other Nonelectric Expenses | 73 | (21 | ) | ||||||
Postretirement Benefits—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy: | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 375 | $ | 315 | |||||
Interest Cost on Projected Benefit Obligation | 550 | 558 | |||||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 51 | 51 | |||||||
From Other Comprehensive Income1 | 1 | 1 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 48 | -- | |||||||
From Other Comprehensive Income1 | 1 | -- | |||||||
Net Periodic Postretirement Benefit Cost | $ | 1,026 | $ | 925 | |||||
Effect of Medicare Part D Subsidy | $ | (450 | ) | $ | (308 | ) | |||
1 Corporate cost included in Other Nonelectric Expenses. | |||||||||
Fair_Value_of_Financial_Instru
Fair Value of Financial Instruments | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
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: | |||||||||||||||||
Cash and Short-Term Investments—The carrying amount approximates fair value because of the short-term maturity of those instruments. | |||||||||||||||||
Short-Term Debt—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of March 31, 2015 and December 31, 2014 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates. | |||||||||||||||||
Long-Term Debt including Current Maturities—The fair value of the Company’s and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820. | |||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
(in thousands) | Carrying | Fair Value | Carrying | Fair Value | |||||||||||||
Amount | Amount | ||||||||||||||||
Cash and Cash Equivalents | $ | 157 | $ | 157 | $ | -- | $ | -- | |||||||||
Short-Term Debt | (48,652 | ) | (48,652 | ) | (10,854 | ) | (10,854 | ) | |||||||||
Long-Term Debt including Current Maturities | (498,641 | ) | (571,801 | ) | (498,690 | ) | (600,828 | ) |
Income_Tax_Expense_Continuing_
Income Tax Expense Continuing Operations | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
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, 2015 and 2014: | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Income Before Income Taxes – Continuing Operations | $ | 17,854 | $ | 30,341 | |||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) | 6,963 | 11,833 | |||||||
Increases (Decreases) in Tax from: | |||||||||
Federal Production Tax Credits | (2,054 | ) | (2,252 | ) | |||||
Section 199 Domestic Production Activities Deduction | (362 | ) | (358 | ) | |||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (212 | ) | (212 | ) | |||||
Employee Stock Ownership Plan Dividend Deduction | (172 | ) | (189 | ) | |||||
AFUDC Equity | (100 | ) | (133 | ) | |||||
Corporate Owned Life Insurance | (80 | ) | (112 | ) | |||||
Other Items – Net | 90 | (15 | ) | ||||||
Income Tax Expense – Continuing Operations | $ | 4,073 | $ | 8,562 | |||||
Effective Income Tax Rate – Continuing Operations | 22.8 | % | 28.2 | % | |||||
The following table summarizes the activity related to our unrecognized tax benefits: | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Balance on January 1 | $ | 222 | $ | 4,239 | |||||
Increases Related to Tax Positions for Prior Years | -- | 137 | |||||||
Increases Related to Tax Positions for Current Year | 44 | -- | |||||||
Uncertain Positions Resolved During Year | -- | -- | |||||||
Balance on March 31 | $ | 266 | $ | 4,376 | |||||
The balance of unrecognized tax benefits as of March 31, 2015 would reduce our effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31, 2015 is not expected to change significantly within the next twelve months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. No interest is accrued on tax uncertainties as of March 31, 2015. | |||||||||
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state and foreign income tax returns. As of March 31, 2015, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2011. On September 13, 2013 the IRS and U.S. Treasury issued final regulations on the deductibility and capitalization of expenditures related to tangible property, generally effective for tax years beginning on or after January 1, 2014. Taxpayers were allowed to elect early adoption of the regulations for the 2012 or 2013 tax year. Deferred tax liabilities at March 31, 2015 are not materially affected by the regulations. The final regulations do not impact the effect of Revenue Procedure 2013-24 issued on April 30, 2013, which provided guidance for repairs related to generation property. Among other things, the Revenue Procedure listed units of property and material components of units of property for purposes of analyzing repair versus capitalization issues. The Company will adopt Revenue Procedure 2013-24 and the final tangible property regulations for income tax filings for tax year 2014. |
Discontinued_Operations
Discontinued Operations | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Discontinued Operations and Disposal Groups [Abstract] | |||||||||
Discontinued Operations | 16. Discontinued Operations | ||||||||
In 2014 the Company entered into signed letters of intent to sell its two construction companies that made up its Construction segment. On April 30, 2015 the Company sold Foley Company (Foley), its former water, wastewater, power and industrial construction contractor headquartered in Kansas City, Missouri, for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. On February 28, 2015 the Company sold the assets of its former energy and electrical construction contractor headquartered in Moorhead, Minnesota (AEV, Inc.) in exchange for $22.3 million in cash plus an estimated $0.9 million in adjustments for working capital and fixed assets to be determined within 90 days of closing. The Company recorded an estimated $7.2 million net-of-tax gain on the sale of AEV, Inc. The assets, liabilities, operating results and cash flows of Foley and AEV, Inc. are being reported as discontinued operations as of, and for the periods preceding, March 31, 2015. On February 8, 2013 the Company completed the sale of substantially all the assets of its former waterfront equipment manufacturing company previously included in the Company’s Manufacturing segment. On November 30, 2012 the Company completed the sale of the assets of its former wind tower manufacturing company. The following summary presentations of the results of discontinued operations for the three-month periods ended March 31, 2015 and 2014, include the operating results of Foley, AEV, Inc. and residual expenses from the Company’s former wind tower and waterfront equipment manufacturers: | |||||||||
For the Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Operating Revenues | $ | 18,724 | $ | 25,506 | |||||
Operating Expenses | 22,141 | 26,368 | |||||||
Goodwill Impairment Charge | 1,000 | -- | |||||||
Operating Loss | (4,417 | ) | (862 | ) | |||||
Other (Deductions) Income | (31 | ) | 288 | ||||||
Income Tax Benefit | (1,376 | ) | (225 | ) | |||||
Net Loss from Operations | (3,072 | ) | (349 | ) | |||||
Gain on Disposition Before Taxes | 12,042 | -- | |||||||
Income Tax Expense on Disposition | 4,816 | -- | |||||||
Net Gain on Disposition | 7,226 | -- | |||||||
Net Income (Loss) | $ | 4,154 | $ | (349 | ) | ||||
Following are summary presentations of the major components of assets and liabilities of discontinued operations as of March 31, 2015 and December 31, 2014: | |||||||||
(in thousands) | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Current Assets | $ | 26,928 | $ | 35,174 | |||||
Goodwill and Intangibles | 1,814 | 2,814 | |||||||
Net Plant | 4,429 | 10,669 | |||||||
Assets of Discontinued Operations | $ | 33,171 | $ | 48,657 | |||||
Current Liabilities | $ | 15,616 | $ | 22,864 | |||||
Deferred Income Taxes | 5,116 | 4,695 | |||||||
Liabilities of Discontinued Operations | $ | 20,732 | $ | 27,559 | |||||
Foley and AEV, Inc. entered into fixed-price construction contracts. Revenues under these contracts have been recognized on a percentage-of-completion basis. The method used to determine the progress of completion is based on the ratio of costs incurred to total estimated costs on construction projects. | |||||||||
The following tables summarize costs incurred and billings and estimated earnings recognized on uncompleted contracts included in current assets and current liabilities of discontinued operations: | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Costs Incurred on Uncompleted Contracts | $ | 339,594 | $ | 402,332 | |||||
Less Billings to Date | (354,256 | ) | (411,909 | ) | |||||
Plus Estimated Earnings Recognized | 14,458 | 15,154 | |||||||
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | $ | (204 | ) | $ | 5,577 | ||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts | $ | 3,216 | $ | 8,133 | |||||
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | (3,420 | ) | (2,556 | ) | |||||
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | $ | (204 | ) | $ | 5,577 | ||||
The Company has a standard quarterly Estimate at Completion process in which management reviews the progress and performance of the Company’s contracts accounted for under percentage-of-completion accounting. As part of this process, management reviews include, but are not limited to, any outstanding key contract matters, progress towards completion and the related program schedule, identified risks and opportunities, and the related changes in estimates of revenues and costs. The risks and opportunities include management’s judgment about the ability and cost to achieve the schedule, technical requirements and other contract requirements. Management must make assumptions regarding labor productivity and availability, the complexity of the work to be performed, the availability of materials, the length of time to complete the contract, and performance by subcontractors, among other variables. Based on this analysis, any adjustments to net sales, costs of sales, and the related impact to operating income are recorded as necessary in the period they become known. These adjustments may result from positive program performance and an increase in operating profit during the performance of individual contracts if management determines it will be successful in mitigating risks surrounding the technical, schedule, and cost aspects of those contracts or realizing related opportunities. Likewise, these adjustments may result in a decrease in operating profit if management determines it will not be successful in mitigating these risks or realizing related opportunities. Changes in estimates of net sales, costs of sales, and the related impact to operating income are recognized using a cumulative catch-up, which recognizes, in the current period, the cumulative effect of the changes on current and prior periods based on a contract’s percent complete. A significant change in one or more of these estimates could affect the profitability of one or more of the Company’s contracts. If a loss is indicated at a point in time during a contract, a projected loss for the entire contract is estimated and recognized. An increase in estimated costs on one large job in progress at Foley in excess of previous period cost estimates resulted in $2.3 million in pretax charges in the first quarter of 2015. | |||||||||
In the fourth quarter of 2014 the Company entered into negotiations to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge as a result of a revision in the estimated valuation of Foley due to first quarter financial results. The first quarter 2015 goodwill impairment loss is reflected in the results of discontinued operations and the remaining goodwill balance related to Foley is included in assets of discontinued operations. | |||||||||
Included in current liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow: | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Warranty Reserve Balance, January 1 | $ | 2,527 | $ | 3,087 | |||||
Additional Provision for Warranties Made During the Year | -- | -- | |||||||
Settlements Made During the Year | (6 | ) | -- | ||||||
Decrease in Warranty Estimates for Prior Years | -- | (100 | ) | ||||||
Warranty Reserve Balance, March 31 | $ | 2,521 | $ | 2,987 | |||||
The warranty reserve balances as of March 31, 2015 relate entirely to warranties scheduled to expire over the next five years on products produced by the Company’s former wind tower and waterfront equipment manufacturing companies. Expenses associated with remediation activities of these companies could be substantial. 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 these companies produced prior to the companies being sold. 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 results of operations and financial condition. | |||||||||
Retainage | |||||||||
Assets of discontinued operations include the following amounts billed under contracts by the Company’s construction companies that have been retained by customers pending project completion: | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Accounts Receivable Retained by Customers | $ | 4,018 | $ | 6,759 |
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | 17. Subsequent Events |
Sale of Foley | |
On April 30, 2015 the Company completed the sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. Although the net carrying value of Foley had been adjusted to its indicated fair value through goodwill impairment charges recorded prior to the sale based on acceptance of the buyer’s offering price, the final proceeds and loss on sale will not be known until the adjustments for working capital and other related items have been determined. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
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, and the price is fixed or determinable. 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. In the case of derivative instruments, such as Otter Tail Power Company (OTP) forward energy contracts, marked-to-market and realized gains and losses are recognized on a net basis in revenue in accordance with the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging. 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. | |||||||||||||||||||||
Warranty Reserves | Warranty Reserves | ||||||||||||||||||||
The Company establishes reserves for estimated product warranty costs at the time revenue is recognized based on historical warranty experience and additionally for any known product warranty issues. Certain products previously sold by the Company carried one to fifteen year warranties. Although the Company engaged in extensive product quality programs and processes, the Company’s warranty obligations have been and may in the future be affected by product failure rates, repair or field replacement costs and additional development costs incurred in correcting product failures. The Company’s warranty reserve balances as of March 31, 2015 and December 31, 2014 relate entirely to products that were produced by IMD, Inc. and Shrco, Inc. prior to the Company selling the assets of these companies and are included in liabilities of discontinued operations. See note 16 to consolidated financial statements. | |||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements | ||||||||||||||||||||
The Company follows ASC Topic 820, Fair Value Measurements and Disclosures (ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows: | |||||||||||||||||||||
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (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, 2015 and December 31, 2014: | |||||||||||||||||||||
March 31, 2015 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 381 | |||||||||||||||
Investments: | |||||||||||||||||||||
Money Market Deposit Escrow Account – AEV, Inc. Sale | 2,000 | ||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,625 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,229 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 550 | ||||||||||||||||||||
Total Assets | $ | 2,550 | $ | 7,854 | $ | 381 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | $ | -- | $ | 282 | $ | -- | |||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 11,285 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 282 | $ | 11,285 | |||||||||||||||
December 31, 2014 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 257 | |||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 120 | ||||||||||||||||||||
Investments: | |||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,761 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,253 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 593 | ||||||||||||||||||||
Total Assets | $ | 713 | $ | 8,014 | $ | 257 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | $ | -- | $ | 342 | $ | -- | |||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 13,888 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 342 | $ | 13,888 | |||||||||||||||
The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows: | |||||||||||||||||||||
Forward Gasoline Purchase Contracts – These contracts are priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts. Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts with the same settlement periods. | |||||||||||||||||||||
Corporate and U.S. Government-Sponsored Enterprises’ Debt Securities Held by the Company’s Captive Insurance Company – Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes. | |||||||||||||||||||||
Fair values for OTP’s forward energy contracts with delivery points that are not at an active trading hub included in Level 3 of the fair value hierarchy in the table above as of March 31, 2015 and December 31, 2014, are based on prices indexed to observable prices at an active trading hub. Prices at illiquid trading points are based on a basis spread between that trading point and more liquid trading hub prices. These basis spreads are determined based on available market price information and the use of forward price curve models. The March 31, 2015 Level 3 forward electric basis spreads ranged from $2.46 to $8.00 per megawatt-hour under the active trading hub price. The weighted average price was $34.45 per megawatt-hour. | |||||||||||||||||||||
In the table above, the fair value of the Level 3 forward energy contracts in derivative asset and derivative liability positions as of March 31, 2015 are related to power purchase contracts where OTP intends to take or has taken physical delivery of the energy under the contract. When OTP takes physical delivery of the energy purchased under these contracts the costs incurred are subject to recovery in base rates and through fuel clause adjustments. Any derivative assets or liabilities and related gains or losses recorded as a result of the fair valuation of these power purchase contracts will not be realized and are 100% offset by regulatory liabilities and assets related to fuel clause adjustment treatment of purchased power costs. Therefore, the net impact of any recorded fair valuation gains or losses related to these contracts on the Company’s consolidated net income is $0 and the net income impact of any future fair valuation adjustments of these contracts will be $0. When energy is delivered under these contracts, they will be settled at the original contract price and any fair valuation gains or losses and related derivative assets or liabilities recorded over the life of the contracts will be reversed along with any offsetting regulatory liabilities or assets. Because of regulatory accounting treatment, any price volatility related to the fair valuation of these contracts had no impact on the Company’s reported consolidated net income for the three month periods ended March 31, 2015 and 2014. | |||||||||||||||||||||
The following table presents changes in Level 3 forward energy contract derivative asset and liability fair valuations for the three month periods ended March 31, 2015 and 2014: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Forward Energy Contracts - Fair Values Beginning of Period | $ | (13,631 | ) | $ | (11,341 | ) | |||||||||||||||
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods | 3,386 | 1,160 | |||||||||||||||||||
Net Changes in Fair Value of Contracts Entered into in Prior Periods | (368 | ) | 3,498 | ||||||||||||||||||
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period | (10,613 | ) | (6,683 | ) | |||||||||||||||||
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period | (291 | ) | 40 | ||||||||||||||||||
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period | $ | (10,904 | ) | $ | (6,643 | ) | |||||||||||||||
Inventories | Inventories | ||||||||||||||||||||
Inventories consist of the following: | |||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Finished Goods | $ | 27,607 | $ | 27,998 | |||||||||||||||||
Work in Process | 9,894 | 10,628 | |||||||||||||||||||
Raw Material, Fuel and Supplies | 47,014 | 46,577 | |||||||||||||||||||
Total Inventories | $ | 84,515 | $ | 85,203 | |||||||||||||||||
Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets | ||||||||||||||||||||
An assessment of the carrying amounts of the goodwill of the Company’s reporting units reported under continuing operations as of December 31, 2014 indicated the fair values are substantially in excess of their respective book values and not impaired. | |||||||||||||||||||||
The following table summarizes changes to goodwill by business segment during 2015: | |||||||||||||||||||||
Gross Balance | Accumulated Impairments | Balance (net of impairments) | Adjustments to Goodwill in 2015 | Balance (net of impairments) | |||||||||||||||||
(in thousands) | December 31, | December 31, | March 31, | ||||||||||||||||||
2014 | 2014 | 2015 | |||||||||||||||||||
Manufacturing | $ | 12,186 | $ | -- | $ | 12,186 | $ | -- | $ | 12,186 | |||||||||||
Plastics | 19,302 | -- | 19,302 | -- | 19,302 | ||||||||||||||||
Total | $ | 31,488 | $ | -- | $ | 31,488 | $ | -- | $ | 31,488 | |||||||||||
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. In the first quarter of 2015, OTP began purchasing emission allowances to apply against sulfur dioxide emissions from Hoot Lake Plant. The cost of unused emission allowances is included in intangible assets on the Company’s March 31, 2015 balance sheets. The following table summarizes the components of the Company’s intangible assets at March 31, 2015 and December 31, 2014: | |||||||||||||||||||||
March 31, 2015 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying | Remaining | |||||||||||||||||
Amount | Amortization | ||||||||||||||||||||
Periods | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,996 | $ | 10,815 | 57-157 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 447 | 192 | 18 months | |||||||||||||||||
Emission Allowances | 106 | -- | 106 | Expensed as used | |||||||||||||||||
Total | $ | 17,556 | $ | 6,443 | $ | 11,113 | |||||||||||||||
December 31, 2014 (in thousands) | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,784 | $ | 11,027 | 60-160 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 415 | 224 | 21 months | |||||||||||||||||
Total | $ | 17,450 | $ | 6,199 | $ | 11,251 | |||||||||||||||
The amortization expense for these intangible assets was: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Amortization Expense – Intangible Assets | $ | 244 | $ | 244 | |||||||||||||||||
The estimated annual amortization expense for these intangible assets for the next five years is: | |||||||||||||||||||||
(in thousands) | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||
Estimated Amortization Expense – Intangible Assets | $ | 977 | $ | 945 | $ | 849 | $ | 849 | $ | 849 | |||||||||||
The following table presents a reconciliation of OTP’s emission allowances balance for the three month period ended March 31, 2015: | |||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
(in thousands) | 31-Mar-15 | ||||||||||||||||||||
Emission Allowances Beginning Balance | $ | -- | |||||||||||||||||||
Allowances Purchased | 168 | ||||||||||||||||||||
Allowances Used | (62 | ) | |||||||||||||||||||
Emission Allowances Ending Balance | $ | 106 | |||||||||||||||||||
Supplemental Disclosures of Cash Flow Information | Supplemental Disclosures of Cash Flow Information | ||||||||||||||||||||
As of March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Noncash Investing Activities: | |||||||||||||||||||||
Accounts Payable Outstanding Related to Capital Additions1 | $ | 32,838 | $ | 22,244 | |||||||||||||||||
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2 | $ | 7,554 | $ | 3,434 | |||||||||||||||||
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. | |||||||||||||||||||||
2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received. | |||||||||||||||||||||
Coyote Station Lignite Supply Agreement - Variable Interest Entity | Coyote Station Lignite Supply Agreement – Variable Interest Entity—In October 2012, the Coyote Station owners, including OTP, entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton to be paid by the Coyote Station owners under the LSA will reflect the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining lignite coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements. | ||||||||||||||||||||
Under the LSA, all development period costs of the Coyote Creek coal mine incurred during the development period will be recovered from the Coyote Station owners over the full term of the production period, which commences with the first delivery of coal to Coyote Station, scheduled for May 2016, by being included in the cost of production. The development fee and the capital charge incurred during the development period will be recovered from the Coyote Station owners over the first 52 months of the production period by being included in the cost of production during those months. The LSA was amended on March 16, 2015 to provide that, during any period between December 31, 2016 and the date on which CCMC makes initial deliveries of lignite, the Coyote Station owners will pay the following costs of production as advance payments for lignite: depreciation and amortization charges on capital assets and CCMC’s obligations under its loans and leases. In addition, if the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and 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. OTP’s 35% share of development period costs, development fees and capital charges incurred by CCMC through March 31, 2015 is $28.5 million. 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, 2015 could be as high as $28.5 million. | |||||||||||||||||||||
New Accounting Standards | New Accounting Standards | ||||||||||||||||||||
ASU 2014-09—In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. | |||||||||||||||||||||
ASU 2014-09 amendments to the ASC are effective for fiscal years beginning after December 15, 2016, however, in April 2015, the FASB voted to propose a one year deferral of the effective date. The proposed deferral may permit early adoption, but would not allow adoption any earlier than the original effective date of the standard. 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. Early application of the ASU amendments is not permitted. The Company is currently reviewing ASU 2014-09, identifying key impacts to its businesses, reviewing revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and evaluating transition options. | |||||||||||||||||||||
ASU 2015-03—In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 will become effective for interim and annual reporting periods beginning after December 15, 2015 with early adoption permitted. The Company will apply the updated standards in ASU 2015-03 to its consolidated financial statements beginning in the first quarter of 2016. If applied as of March 31, 2015, both the Company’s consolidated long-term assets and long-term debt would be reduced by approximately $2.5 million—the balance of its consolidated unamortized debt issuance costs related to its outstanding long-term debt as of March 31, 2015. | |||||||||||||||||||||
ASU 2015-05—In April 2015, the FASB issued ASU 2015-05: Intangibles—Goodwill and Other—Internal Use Software (Subtopic 350-40) Customers Accounting for Fees Paid in a Cloud Computing Arrangement, to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. The Company will be analyzing its cloud computing arrangements to determine if any such arrangements include software licenses that should be accounted for similar to the acquisition of other software licenses. The Company has not, at this time, estimated what impact, if any, adoption of the updated standard will have on its consolidated financial statements. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||
Schedule of assets and liabilities that are measured at fair value on a recurring basis | March 31, 2015 (in thousands) | Level 1 | Level 2 | Level 3 | |||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 381 | |||||||||||||||
Investments: | |||||||||||||||||||||
Money Market Deposit Escrow Account – AEV, Inc. Sale | 2,000 | ||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,625 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,229 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 550 | ||||||||||||||||||||
Total Assets | $ | 2,550 | $ | 7,854 | $ | 381 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | -- | $ | 282 | $ | -- | ||||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 11,285 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 282 | $ | 11,285 | |||||||||||||||
December 31, 2014 (in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||||||
Assets: | |||||||||||||||||||||
Current Assets – Other: | |||||||||||||||||||||
Forward Energy Contracts | $ | -- | $ | -- | $ | 257 | |||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 120 | ||||||||||||||||||||
Investments: | |||||||||||||||||||||
Corporate Debt Securities – Held by Captive Insurance Company | 6,761 | ||||||||||||||||||||
U.S. Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company | 1,253 | ||||||||||||||||||||
Other Assets: | |||||||||||||||||||||
Money Market and Mutual Funds - Nonqualified Retirement Savings Plan | 593 | ||||||||||||||||||||
Total Assets | $ | 713 | $ | 8,014 | $ | 257 | |||||||||||||||
Liabilities: | |||||||||||||||||||||
Derivative Liabilities - Forward Gasoline Purchase Contracts | $ | -- | $ | 342 | $ | -- | |||||||||||||||
Derivative Liabilities - Forward Energy Contracts | 13,888 | ||||||||||||||||||||
Total Liabilities | $ | -- | $ | 342 | $ | 13,888 | |||||||||||||||
Schedule of derivative asset and liability fair valuations | Three Months Ended | ||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Forward Energy Contracts - Fair Values Beginning of Period | $ | (13,631 | ) | $ | (11,341 | ) | |||||||||||||||
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods | 3,386 | 1,160 | |||||||||||||||||||
Net Changes in Fair Value of Contracts Entered into in Prior Periods | (368 | ) | 3,498 | ||||||||||||||||||
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period | (10,613 | ) | (6,683 | ) | |||||||||||||||||
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period | (291 | ) | 40 | ||||||||||||||||||
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period | $ | (10,904 | ) | $ | (6,643 | ) | |||||||||||||||
Schedule of inventories | March 31, | December 31, | |||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Finished Goods | $ | 27,607 | $ | 27,998 | |||||||||||||||||
Work in Process | 9,894 | 10,628 | |||||||||||||||||||
Raw Material, Fuel and Supplies | 47,014 | 46,577 | |||||||||||||||||||
Total Inventories | $ | 84,515 | $ | 85,203 | |||||||||||||||||
Schedule of changes to goodwill by business segment | Gross Balance | Accumulated Impairments | Balance (net of impairments) | Adjustments to Goodwill in 2015 | Balance (net of impairments) | ||||||||||||||||
(in thousands) | December 31, | December 31, | March 31, | ||||||||||||||||||
2014 | 2014 | 2015 | |||||||||||||||||||
Manufacturing | $ | 12,186 | $ | -- | $ | 12,186 | $ | -- | $ | 12,186 | |||||||||||
Plastics | 19,302 | -- | 19,302 | -- | 19,302 | ||||||||||||||||
Total | $ | 31,488 | $ | -- | $ | 31,488 | $ | -- | $ | 31,488 | |||||||||||
Schedule of components of intangible assets | March 31, 2015 (in thousands) | Gross Carrying Amount | Accumulated Amortization | Net Carrying | Remaining | ||||||||||||||||
Amount | Amortization | ||||||||||||||||||||
Periods | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,996 | $ | 10,815 | 57-157 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 447 | 192 | 18 months | |||||||||||||||||
Emission Allowances | 106 | -- | 106 | Expensed as used | |||||||||||||||||
Total | $ | 17,556 | $ | 6,443 | $ | 11,113 | |||||||||||||||
December 31, 2014 (in thousands) | |||||||||||||||||||||
Amortizable Intangible Assets: | |||||||||||||||||||||
Customer Relationships | $ | 16,811 | $ | 5,784 | $ | 11,027 | 60-160 months | ||||||||||||||
Other Intangible Assets Including Contracts | 639 | 415 | 224 | 21 months | |||||||||||||||||
Total | $ | 17,450 | $ | 6,199 | $ | 11,251 | |||||||||||||||
Schedule of amortization expense for intangible assets | The amortization expense for these intangible assets was: | ||||||||||||||||||||
Three Months Ended | |||||||||||||||||||||
March 31, | |||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Amortization Expense – Intangible Assets | $ | 244 | $ | 244 | |||||||||||||||||
The estimated annual amortization expense for these intangible assets for the next five years is: | |||||||||||||||||||||
(in thousands) | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||
Estimated Amortization Expense – Intangible Assets | $ | 977 | $ | 945 | $ | 849 | $ | 849 | $ | 849 | |||||||||||
Schedule of reconciliation of OTP's emission allowances | Three Months Ended | ||||||||||||||||||||
(in thousands) | 31-Mar-15 | ||||||||||||||||||||
Emission Allowances Beginning Balance | $ | -- | |||||||||||||||||||
Allowances Purchased | 168 | ||||||||||||||||||||
Allowances Used | (62 | ) | |||||||||||||||||||
Emission Allowances Ending Balance | $ | 106 | |||||||||||||||||||
Schedule of supplemental disclosure of cash flow information | As of March 31, | ||||||||||||||||||||
(in thousands) | 2015 | 2014 | |||||||||||||||||||
Noncash Investing Activities: | |||||||||||||||||||||
Accounts Payable Outstanding Related to Capital Additions1 | $ | 32,838 | $ | 22,244 | |||||||||||||||||
Accounts Receivable Outstanding Related to Joint Plant Owner’s Share of Capital Additions2 | $ | 7,554 | $ | 3,434 | |||||||||||||||||
1Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. | |||||||||||||||||||||
2Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received. |
Segment_Information_Tables
Segment Information (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Segment Reporting [Abstract] | |||||||||
Schedule of percent of consolidated sales revenue by country | Three Months Ended March 31, | ||||||||
2015 | 2014 | ||||||||
United States of America | 96.3 | % | 97.2 | % | |||||
Mexico | 3 | % | 2.2 | % | |||||
Canada | 0.6 | % | 0.5 | % | |||||
All Other Countries (none individually greater than 0.05%) | 0.1 | % | 0.1 | % | |||||
Schedule of information by business segments | |||||||||
Operating Revenue | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 113,547 | $ | 119,088 | |||||
Manufacturing | 56,759 | 55,435 | |||||||
Plastics | 32,552 | 40,483 | |||||||
Intersegment Eliminations | (17 | ) | (40 | ) | |||||
Total | $ | 202,841 | $ | 214,966 | |||||
Interest Charges | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 6,121 | $ | 5,079 | |||||
Manufacturing | 832 | 808 | |||||||
Plastics | 246 | 247 | |||||||
Corporate and Intersegment Eliminations | 544 | 461 | |||||||
Total | $ | 7,743 | $ | 6,595 | |||||
Income Taxes | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 4,221 | $ | 5,750 | |||||
Manufacturing | 504 | 1,671 | |||||||
Plastics | 1,264 | 2,133 | |||||||
Corporate | (1,916 | ) | (992 | ) | |||||
Total | $ | 4,073 | $ | 8,562 | |||||
Net Income | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 13,178 | $ | 16,653 | |||||
Manufacturing | 1,184 | 2,896 | |||||||
Plastics | 2,120 | 3,460 | |||||||
Corporate | (2,701 | ) | (1,230 | ) | |||||
Discontinued Operations | 4,154 | (349 | ) | ||||||
Total | $ | 17,935 | $ | 21,430 | |||||
Identifiable Assets | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Electric | $ | 1,484,289 | $ | 1,472,647 | |||||
Manufacturing | 139,143 | 130,701 | |||||||
Plastics | 90,256 | 87,356 | |||||||
Corporate | 68,321 | 51,918 | |||||||
Assets of Discontinued Operations | 33,171 | 48,657 | |||||||
Total | $ | 1,815,180 | $ | 1,791,279 |
Rate_and_Regulatory_Matters_Ta
Rate and Regulatory Matters (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Rate and Regulatory Matters [Abstract] | |||||||||
Schedule of revenues recorded under rate riders | Three Months Ended March 31, | ||||||||
Rate Rider (in thousands) | 2015 | 2014 | |||||||
Minnesota | |||||||||
Conservation Improvement Program Costs and Incentives1 | $ | 1,928 | $ | 1,521 | |||||
Transmission Cost Recovery | 1,615 | 2,304 | |||||||
Environmental Cost Recovery | 2,557 | 1,763 | |||||||
North Dakota | |||||||||
Renewable Resource Adjustment | 1,883 | 1,435 | |||||||
Transmission Cost Recovery | 1,936 | 1,514 | |||||||
Environmental Cost Recovery | 2,156 | 1,522 | |||||||
Big Stone II Project Costs | -- | 361 | |||||||
South Dakota | |||||||||
Transmission Cost Recovery | 363 | 346 | |||||||
Environmental Cost Recovery | 504 | -- | |||||||
1Includes MNCIP costs recovered in base rates. |
Regulatory_Assets_and_Liabilit1
Regulatory Assets and Liabilities (Tables) | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | ||||||||||||||
Schedule of amount of regulatory assets and liabilities | 31-Mar-15 | Remaining | ||||||||||||
Recovery/ | ||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period | ||||||||||
Regulatory Assets: | ||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 7,465 | $ | 99,659 | $ | 107,124 | see below | |||||||
Deferred Marked-to-Market Losses1 | 2,059 | 9,226 | 11,285 | 69 months | ||||||||||
Conservation Improvement Program Costs and Incentives2 | 3,815 | 3,511 | 7,326 | 27 months | ||||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | -- | 5,305 | 5,305 | asset lives | ||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 2,152 | 1,835 | 3,987 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 601 | 3,086 | 3,687 | 93 months | ||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 2,140 | 636 | 2,776 | 24 months | ||||||||||
Debt Reacquisition Premiums1 | 351 | 1,802 | 2,153 | 210 months | ||||||||||
Deferred Income Taxes1 | -- | 1,461 | 1,461 | asset lives | ||||||||||
Recoverable Fuel and Purchased Power Costs1 | 1,249 | -- | 1,249 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – South Dakota2 | 100 | 718 | 818 | 98 months | ||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Revenues2 | 420 | -- | 420 | 12 months | ||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | -- | 68 | 68 | see below | ||||||||||
North Dakota Renewable Resource Rider Accrued Revenues2 | -- | 61 | 61 | 12 months | ||||||||||
Total Regulatory Assets | $ | 20,352 | $ | 127,368 | $ | 147,720 | ||||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | $ | -- | $ | 75,220 | $ | 75,220 | asset lives | |||||||
North Dakota Renewable Resource Rider Accrued Refund | 1,803 | -- | 1,803 | 12 months | ||||||||||
Deferred Income Taxes | -- | 1,447 | 1,447 | asset lives | ||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | -- | 908 | 908 | see below | ||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Refund | 451 | -- | 451 | 12 months | ||||||||||
Deferred Marked-to-Market Gains | 204 | 177 | 381 | 58 months | ||||||||||
Big Stone II Over Recovered Project Costs – North Dakota | 111 | -- | 111 | 9 months | ||||||||||
Deferred Gain on Sale of Utility Property – Minnesota Portion | 6 | 99 | 105 | 225 months | ||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Refund | 86 | -- | 86 | 12 months | ||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 48 | -- | 48 | 12 months | ||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Refund | 35 | -- | 35 | 12 months | ||||||||||
Total Regulatory Liabilities | $ | 2,744 | $ | 77,851 | $ | 80,595 | ||||||||
Net Regulatory Asset Position | $ | 17,608 | $ | 49,517 | $ | 67,125 | ||||||||
1Costs subject to recovery without a rate of return. | ||||||||||||||
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. | ||||||||||||||
31-Dec-14 | Remaining | |||||||||||||
Recovery/ | ||||||||||||||
(in thousands) | Current | Long-Term | Total | Refund Period | ||||||||||
Regulatory Assets: | ||||||||||||||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits1 | $ | 7,464 | $ | 101,526 | $ | 108,990 | see below | |||||||
Deferred Marked-to-Market Losses1 | 4,492 | 9,396 | 13,888 | 72 months | ||||||||||
Conservation Improvement Program Costs and Incentives2 | 5,843 | 2,500 | 8,343 | 18 months | ||||||||||
Accumulated ARO Accretion/Depreciation Adjustment1 | -- | 5,190 | 5,190 | asset lives | ||||||||||
Big Stone II Unrecovered Project Costs – Minnesota1 | 592 | 3,207 | 3,799 | 96 months | ||||||||||
Minnesota Transmission Cost Recovery Rider Accrued Revenues2 | 943 | 2,455 | 3,398 | 24 months | ||||||||||
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up1 | 2,585 | 807 | 3,392 | 24 months | ||||||||||
Debt Reacquisition Premiums1 | 351 | 1,890 | 2,241 | 213 months | ||||||||||
Deferred Income Taxes1 | -- | 2,086 | 2,086 | asset lives | ||||||||||
Recoverable Fuel and Purchased Power Costs1 | 1,114 | -- | 1,114 | 12 months | ||||||||||
North Dakota Transmission Cost Recovery Rider Accrued Revenues2 | 859 | -- | 859 | 12 months | ||||||||||
Big Stone II Unrecovered Project Costs – South Dakota2 | 100 | 743 | 843 | 101 months | ||||||||||
North Dakota Environmental Cost Recovery Rider Accrued Revenues2 | 706 | -- | 706 | 12 months | ||||||||||
Minnesota Environmental Cost Recovery Rider Accrued Revenues2 | 186 | -- | 186 | 12 months | ||||||||||
Minnesota Renewable Resource Rider Accrued Revenues2 | -- | 68 | 68 | see below | ||||||||||
South Dakota Environmental Cost Recovery Rider Accrued Revenues2 | 38 | -- | 38 | 12 months | ||||||||||
Total Regulatory Assets | $ | 25,273 | $ | 129,868 | $ | 155,141 | ||||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated Reserve for Estimated Removal Costs – Net of Salvage | $ | -- | $ | 74,237 | $ | 74,237 | asset lives | |||||||
Deferred Income Taxes | -- | 1,550 | 1,550 | asset lives | ||||||||||
North Dakota Renewable Resource Rider Accrued Refund | 933 | 85 | 1,018 | 15 months | ||||||||||
Revenue for Rate Case Expenses Subject to Refund – Minnesota | -- | 784 | 784 | see below | ||||||||||
Deferred Marked-to-Market Gains | -- | 257 | 257 | 67 months | ||||||||||
Big Stone II Over Recovered Project Costs – North Dakota | 147 | -- | 147 | 12 months | ||||||||||
Deferred Gain on Sale of Utility Property – Minnesota Portion | 6 | 100 | 106 | 228 months | ||||||||||
South Dakota Transmission Cost Recovery Rider Accrued Refund | 48 | -- | 48 | 12 months | ||||||||||
South Dakota – Nonasset-Based Margin Sharing Excess | 24 | -- | 24 | 12 months | ||||||||||
Total Regulatory Liabilities | $ | 1,158 | $ | 77,013 | $ | 78,171 | ||||||||
Net Regulatory Asset Position | $ | 24,115 | $ | 52,855 | $ | 76,970 | ||||||||
1Costs subject to recovery without a rate of return. | ||||||||||||||
2Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Forward_Contracts_Classified_a1
Forward Contracts Classified as Derivatives (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||
Schedule for balance sheet location and fair value amounts of the company's forward energy contracts classified as derivatives | |||||||||
(in thousands) | 31-Mar-15 | 31-Dec-14 | |||||||
Current Asset – Marked-to-Market Gain | $ | 381 | $ | 257 | |||||
Regulatory Asset – Current Deferred Marked-to-Market Loss | 2,059 | 4,492 | |||||||
Regulatory Asset – Long-Term Deferred Marked-to-Market Loss | 9,226 | 9,396 | |||||||
Total Assets | 11,666 | 14,145 | |||||||
Current Liability – Marked-to-Market Loss | (11,285 | ) | (13,888 | ) | |||||
Regulatory Liability – Current Deferred Marked-to-Market Gain | (204 | ) | -- | ||||||
Regulatory Liability – Long-Term Deferred Marked-to-Market Gain | (177 | ) | (257 | ) | |||||
Total Liabilities | (11,666 | ) | (14,145 | ) | |||||
Net Fair Value of Marked-to-Market Energy Contracts | $ | -- | $ | -- | |||||
(in thousands) | Year-to-Date | Year-to-Date | |||||||
31-Mar-15 | 31-Mar-14 | ||||||||
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year | $ | -- | $ | 115 | |||||
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods | -- | (72 | ) | ||||||
Changes in Fair Value of Contracts Entered into in Prior Periods | -- | (43 | ) | ||||||
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period | -- | -- | |||||||
Changes in Fair Value of Contracts Entered into in Current Period | -- | 39 | |||||||
Cumulative Fair Value Adjustments Included in Earnings - End of Period | $ | -- | $ | 39 | |||||
Schedule of realized and unrealized net loss on forward energy contracts | |||||||||
Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Net Loss on Forward Electric Energy Contracts | $ | -- | $ | (4 | ) | ||||
Schedule of derivative asset and derivative liability balances subject to legally enforceable netting arrangements | |||||||||
(in thousands) | 31-Mar-15 | 31-Dec-14 | |||||||
Derivative assets subject to legally enforceable netting arrangements | $ | 381 | $ | 257 | |||||
Derivative liabilities subject to legally enforceable netting arrangements | (11,567 | ) | (14,230 | ) | |||||
Net balance subject to legally enforceable netting arrangements | $ | (11,186 | ) | $ | (13,973 | ) | |||
Schedule of breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions | |||||||||
Current Liability – Marked-to-Market Loss (in thousands) | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Loss Contracts Covered by Deposited Funds or Letters of Credit | $ | 282 | $ | 45 | |||||
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade1 | 11,285 | 13,888 | |||||||
Loss Contracts with No Ratings Triggers or Deposit Requirements | -- | 297 | |||||||
Total Current Liability – Marked-to-Market Loss | $ | 11,567 | $ | 14,230 | |||||
1Certain 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 | $ | 11,285 | $ | 13,888 | |||||
Offsetting Gains with Counterparties under Master Netting Agreements | (381 | ) | (257 | ) | |||||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $ | 10,904 | $ | 13,631 |
Reconciliation_of_Common_Share1
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Tables) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
Stockholders Equity and Earnings Per Share [Abstract] | |||||||||||||||||||||
Schedule of reconciliation of common shareholders' equity | |||||||||||||||||||||
(in thousands) | Par Value, | Premium | Retained | Accumulated | Total | ||||||||||||||||
Common | on | Earnings | Other | Common | |||||||||||||||||
Shares | Common | Comprehensive | Equity | ||||||||||||||||||
Shares | Income/(Loss) | ||||||||||||||||||||
Balance, December 31, 2014 | $ | 186,090 | $ | 278,436 | $ | 112,903 | $ | (4,663 | ) | $ | 572,766 | ||||||||||
Common Stock Issuances, Net of Expenses | 1,220 | 6,302 | 7,522 | ||||||||||||||||||
Common Stock Retirements | (195 | ) | (1,044 | ) | (1,239 | ) | |||||||||||||||
Net Income | 17,935 | 17,935 | |||||||||||||||||||
Other Comprehensive Income | 141 | 141 | |||||||||||||||||||
Tax Benefit – Stock Compensation | 24 | 24 | |||||||||||||||||||
Employee Stock Incentive Plans Expense | 623 | 623 | |||||||||||||||||||
Common Dividends ($0.3075 per share) | (11,498 | ) | (11,498 | ) | |||||||||||||||||
Balance, March 31, 2015 | $ | 187,115 | $ | 284,341 | $ | 119,340 | $ | (4,522 | ) | $ | 586,274 | ||||||||||
Schedule of common shares outstanding from December 31, 2014 through March 31, 2015 | |||||||||||||||||||||
Common Shares Outstanding, December 31, 2014 | 37,218,053 | ||||||||||||||||||||
Issuances: | |||||||||||||||||||||
Executive Stock Performance Awards (2012-2014 shares earned) | 89,991 | ||||||||||||||||||||
Automatic Dividend Reinvestment and Share Purchase Plan: | |||||||||||||||||||||
Dividends Reinvested | 42,518 | ||||||||||||||||||||
Cash Invested | 16,553 | ||||||||||||||||||||
At-the-Market Offering | 38,160 | ||||||||||||||||||||
Employee Stock Purchase Plan: | |||||||||||||||||||||
Cash Invested | 19,993 | ||||||||||||||||||||
Dividends Reinvested | 5,985 | ||||||||||||||||||||
Employee Stock Ownership Plan | 21,137 | ||||||||||||||||||||
Stock Options Exercised | 9,000 | ||||||||||||||||||||
Vesting of Restricted Stock Units | 700 | ||||||||||||||||||||
Retirements: | |||||||||||||||||||||
Shares Withheld for Individual Income Tax Requirements | (39,131 | ) | |||||||||||||||||||
Common Shares Outstanding, March 31, 2015 | 37,422,959 | ||||||||||||||||||||
Schedule of reconciliation of weighted average common shares outstanding - basic to weighted average common shares outstanding - diluted | |||||||||||||||||||||
2015 | 2014 | ||||||||||||||||||||
Weighted Average Common Shares Outstanding – Basic | 37,243,118 | 36,240,350 | |||||||||||||||||||
Plus: | |||||||||||||||||||||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers | 229,100 | 131,000 | |||||||||||||||||||
Nonvested Restricted Shares | 83,330 | 90,798 | |||||||||||||||||||
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 70,900 | 55,655 | |||||||||||||||||||
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 40,462 | 39,197 | |||||||||||||||||||
Potentially Dilutive Stock Options | 3,750 | 18,050 | |||||||||||||||||||
Less: | |||||||||||||||||||||
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares | (169,842 | ) | (127,709 | ) | |||||||||||||||||
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options | (2,937 | ) | (15,426 | ) | |||||||||||||||||
Total Dilutive Shares | 254,763 | 191,565 | |||||||||||||||||||
Weighted Average Common Shares Outstanding – Diluted | 37,497,881 | 36,431,915 |
ShareBased_Payments_Tables
Share-Based Payments (Tables) | 3 Months Ended | |||||||||
Mar. 31, 2015 | ||||||||||
Disclosure Of Compensation Related Costs, Share-Based Payments [Abstract] | ||||||||||
Schedule of stock incentive awards granted to the company's executive officers | ||||||||||
Award | Shares/Units | Weighted | Vesting | |||||||
Granted | Average | |||||||||
Grant-Date | ||||||||||
Fair Value | ||||||||||
per Award | ||||||||||
Stock Performance Awards Granted to Executive Officers | 77,500 | $ | 26.99 | 31-Dec-17 | ||||||
Restricted Stock Units Granted to Executive Officers: | ||||||||||
Graded Vesting | 20,900 | $ | 31.675 | 25% per year through February 6, 2019 | ||||||
Cliff Vesting | 6,400 | $ | 31.675 | 100% on February 6, 2020 | ||||||
Schedule of compensation expense under stock-based payment programs | ||||||||||
Three months ended | ||||||||||
March 31, | ||||||||||
(in thousands) | 2015 | 2014 | ||||||||
Employee Stock Purchase Plan (15% discount) | $ | 49 | $ | 42 | ||||||
Restricted Stock Granted to Directors | 98 | 123 | ||||||||
Restricted Stock Granted to Executive Officers | 157 | 135 | ||||||||
Restricted Stock Units Granted to Non-Executive Employees | 66 | 58 | ||||||||
Restricted Stock Units Granted to Executive Officers | 253 | -- | ||||||||
Stock Performance Awards Granted to Executive Officers | 1,020 | 526 | ||||||||
Totals | $ | 1,643 | $ | 884 |
ShortTerm_and_LongTerm_Borrowi1
Short-Term and Long-Term Borrowings (Tables) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||
Schedule of lines of credit | |||||||||||||||||||||
(in thousands) | Line Limit | In Use on | Restricted due to | Available on | Available on | ||||||||||||||||
31-Mar-15 | Outstanding | March 31, | December 31, | ||||||||||||||||||
Letters of Credit | 2015 | 2014 | |||||||||||||||||||
Otter Tail Corporation Credit Agreement | $ | 150,000 | $ | 40,846 | $ | 195 | $ | 108,959 | $ | 138,872 | |||||||||||
OTP Credit Agreement | 170,000 | 7,806 | 560 | 161,634 | 169,440 | ||||||||||||||||
Total | $ | 320,000 | $ | 48,652 | $ | 755 | $ | 270,593 | $ | 308,312 | |||||||||||
Schedule of short-term and long-term debt outstanding | |||||||||||||||||||||
March 31, 2015 (in thousands) | OTP | Otter Tail | Otter Tail | ||||||||||||||||||
Corporation | Corporation | ||||||||||||||||||||
Consolidated | |||||||||||||||||||||
Short-Term Debt | $ | 7,806 | $ | 40,846 | $ | 48,652 | |||||||||||||||
Long-Term Debt: | |||||||||||||||||||||
9.000% Notes, due December 15, 2016 | $ | 52,330 | 52,330 | ||||||||||||||||||
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 | -- | 237 | 237 | ||||||||||||||||||
Partnership in Assisting Community Expansion (PACE) Note, | -- | 1,074 | 1,074 | ||||||||||||||||||
2.54%, due March 18, 2021 | |||||||||||||||||||||
Total | $ | 445,000 | $ | 53,641 | $ | 498,641 | |||||||||||||||
Less: Current Maturities | -- | 204 | 204 | ||||||||||||||||||
Total Long-Term Debt | $ | 445,000 | $ | 53,437 | $ | 498,437 | |||||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 452,806 | $ | 94,487 | $ | 547,293 | |||||||||||||||
December 31, 2014 (in thousands) | OTP | Otter Tail | Otter Tail | ||||||||||||||||||
Corporation | Corporation | ||||||||||||||||||||
Consolidated | |||||||||||||||||||||
Short-Term Debt | $ | -- | $ | 10,854 | $ | 10,854 | |||||||||||||||
Long-Term Debt: | |||||||||||||||||||||
9.000% Notes, due December 15, 2016 | $ | 52,330 | $ | 52,330 | |||||||||||||||||
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 | -- | 256 | 256 | ||||||||||||||||||
Partnership in Assisting Community Expansion (PACE) Note, | -- | 1,105 | 1,105 | ||||||||||||||||||
2.54%, due March 18, 2021 | |||||||||||||||||||||
Total | $ | 445,000 | $ | 53,691 | $ | 498,691 | |||||||||||||||
Less: Current Maturities | -- | 201 | 201 | ||||||||||||||||||
Unamortized Debt Discount | -- | 1 | 1 | ||||||||||||||||||
Total Long-Term Debt | $ | 445,000 | $ | 53,489 | $ | 498,489 | |||||||||||||||
Total Short-Term and Long-Term Debt (with current maturities) | $ | 445,000 | $ | 64,544 | $ | 509,544 |
Pension_Plan_and_Other_Postret1
Pension Plan and Other Postretirement Benefits (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Pension Plan | |||||||||
Schedule of components of net periodic postretirement benefit cost | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 1,500 | $ | 1,175 | |||||
Interest Cost on Projected Benefit Obligation | 3,325 | 3,285 | |||||||
Expected Return on Assets | (4,600 | ) | (4,187 | ) | |||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 47 | 64 | |||||||
From Other Comprehensive Income1 | 1 | 2 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 1,633 | 868 | |||||||
From Other Comprehensive Income1 | 40 | 23 | |||||||
Net Periodic Pension Cost | $ | 1,946 | $ | 1,230 | |||||
1Corporate cost included in Other Nonelectric Expenses. | |||||||||
Executive Survivor and Supplemental Retirement Plan | |||||||||
Schedule of components of net periodic postretirement benefit cost | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 47 | $ | 13 | |||||
Interest Cost on Projected Benefit Obligation | 381 | 380 | |||||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 4 | 5 | |||||||
From Other Comprehensive Income1 | 10 | 13 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 83 | 35 | |||||||
From Other Comprehensive Income2 | 151 | 12 | |||||||
Net Periodic Pension Cost | $ | 676 | $ | 458 | |||||
1Amortization of Prior Service Costs from Other Comprehensive Income Charged to: | |||||||||
Electric Operation and Maintenance Expenses | $ | 4 | $ | 5 | |||||
Other Nonelectric Expenses | 6 | 8 | |||||||
2Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: | |||||||||
Electric Operation and Maintenance Expenses | $ | 78 | $ | 33 | |||||
Other Nonelectric Expenses | 73 | (21 | ) | ||||||
Postretirement Benefits | |||||||||
Schedule of components of net periodic postretirement benefit cost | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Service Cost—Benefit Earned During the Period | $ | 375 | $ | 315 | |||||
Interest Cost on Projected Benefit Obligation | 550 | 558 | |||||||
Amortization of Prior-Service Cost: | |||||||||
From Regulatory Asset | 51 | 51 | |||||||
From Other Comprehensive Income1 | 1 | 1 | |||||||
Amortization of Net Actuarial Loss: | |||||||||
From Regulatory Asset | 48 | -- | |||||||
From Other Comprehensive Income1 | 1 | -- | |||||||
Net Periodic Postretirement Benefit Cost | $ | 1,026 | $ | 925 | |||||
Effect of Medicare Part D Subsidy | $ | (450 | ) | $ | (308 | ) | |||
1 Corporate cost included in Other Nonelectric Expenses. | |||||||||
Fair_Value_of_Financial_Instru1
Fair Value of Financial Instruments (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2015 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Schedule of long-term debt including current maturities | |||||||||||||||||
31-Mar-15 | 31-Dec-14 | ||||||||||||||||
(in thousands) | Carrying | Fair Value | Carrying | Fair Value | |||||||||||||
Amount | Amount | ||||||||||||||||
Cash and Cash Equivalents | $ | 157 | $ | 157 | $ | -- | $ | -- | |||||||||
Short-Term Debt | (48,652 | ) | (48,652 | ) | (10,854 | ) | (10,854 | ) | |||||||||
Long-Term Debt including Current Maturities | (498,641 | ) | (571,801 | ) | (498,690 | ) | (600,828 | ) |
Income_Tax_Expense_Continuing_1
Income Tax Expense - Continuing Operations (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Income Tax Disclosure [Abstract] | |||||||||
Schedule of income from continuing operations before income taxes and income tax expense | |||||||||
Three Months Ended March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Income Before Income Taxes – Continuing Operations | $ | 17,854 | $ | 30,341 | |||||
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%) | 6,963 | 11,833 | |||||||
Increases (Decreases) in Tax from: | |||||||||
Federal Production Tax Credits | (2,054 | ) | (2,252 | ) | |||||
Section 199 Domestic Production Activities Deduction | (362 | ) | (358 | ) | |||||
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes | (212 | ) | (212 | ) | |||||
Employee Stock Ownership Plan Dividend Deduction | (172 | ) | (189 | ) | |||||
AFUDC Equity | (100 | ) | (133 | ) | |||||
Corporate Owned Life Insurance | (80 | ) | (112 | ) | |||||
Other Items – Net | 90 | (15 | ) | ||||||
Income Tax Expense – Continuing Operations | $ | 4,073 | $ | 8,562 | |||||
Effective Income Tax Rate – Continuing Operations | 22.8 | % | 28.2 | % | |||||
Schedule of activity related to unrecognized tax benefits | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Balance on January 1 | $ | 222 | $ | 4,239 | |||||
Increases Related to Tax Positions for Prior Years | -- | 137 | |||||||
Increases Related to Tax Positions for Current Year | 44 | -- | |||||||
Uncertain Positions Resolved During Year | -- | -- | |||||||
Balance on March 31 | $ | 266 | $ | 4,376 |
Discontinued_Operations_Tables
Discontinued Operations (Tables) | 3 Months Ended | ||||||||
Mar. 31, 2015 | |||||||||
Discontinued Operations and Disposal Groups [Abstract] | |||||||||
Schedule of Income and Gains and Losses from Disposition of Discontinued Operations and Schedule of Major Components of Assets and Liabilities of Discontinued Operations | |||||||||
For the Three Months Ended | |||||||||
March 31, | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Operating Revenues | $ | 18,724 | $ | 25,506 | |||||
Operating Expenses | 22,141 | 26,368 | |||||||
Goodwill Impairment Charge | 1,000 | -- | |||||||
Operating Loss | (4,417 | ) | (862 | ) | |||||
Other (Deductions) Income | (31 | ) | 288 | ||||||
Income Tax Benefit | (1,376 | ) | (225 | ) | |||||
Net Loss from Operations | (3,072 | ) | (349 | ) | |||||
Gain on Disposition Before Taxes | 12,042 | -- | |||||||
Income Tax Expense on Disposition | 4,816 | -- | |||||||
Net Gain on Disposition | 7,226 | -- | |||||||
Net Income (Loss) | $ | 4,154 | $ | (349 | ) | ||||
(in thousands) | March 31, | December 31, | |||||||
2015 | 2014 | ||||||||
Current Assets | $ | 26,928 | $ | 35,174 | |||||
Goodwill and Intangibles | 1,814 | 2,814 | |||||||
Net Plant | 4,429 | 10,669 | |||||||
Assets of Discontinued Operations | $ | 33,171 | $ | 48,657 | |||||
Current Liabilities | $ | 15,616 | $ | 22,864 | |||||
Deferred Income Taxes | 5,116 | 4,695 | |||||||
Liabilities of Discontinued Operations | $ | 20,732 | $ | 27,559 | |||||
Schedule of costs incurred and billings and estimated earnings | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Costs Incurred on Uncompleted Contracts | $ | 339,594 | $ | 402,332 | |||||
Less Billings to Date | (354,256 | ) | (411,909 | ) | |||||
Plus Estimated Earnings Recognized | 14,458 | 15,154 | |||||||
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | $ | (204 | ) | $ | 5,577 | ||||
Schedule of costs and estimated earnings in excess of billings and billings in excess of costs and estimated earnings | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts | $ | 3,216 | $ | 8,133 | |||||
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | (3,420 | ) | (2,556 | ) | |||||
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | $ | (204 | ) | $ | 5,577 | ||||
Schedule of warranty reserves | |||||||||
(in thousands) | 2015 | 2014 | |||||||
Warranty Reserve Balance, January 1 | $ | 2,527 | $ | 3,087 | |||||
Additional Provision for Warranties Made During the Year | -- | -- | |||||||
Settlements Made During the Year | (6 | ) | -- | ||||||
Decrease in Warranty Estimates for Prior Years | -- | (100 | ) | ||||||
Warranty Reserve Balance, March 31 | $ | 2,521 | $ | 2,987 | |||||
Schedule of accounts receivable retained by customers pending project completion | |||||||||
March 31, | December 31, | ||||||||
(in thousands) | 2015 | 2014 | |||||||
Accounts Receivable Retained by Customers | $ | 4,018 | $ | 6,759 |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Assets and liabilities measured at fair value on recurring basis (Details) (Fair Value, Measurements, Recurring, USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Level 1 | ||
Assets: | ||
Total Assets | $2,550 | $713 |
Liabilities: | ||
Total Liabilities | ||
Level 1 | Forward Energy Contracts | ||
Assets: | ||
Derivative Assets | ||
Level 1 | Money Market Deposit Escrow | ||
Assets: | ||
Money Market Deposit Escrow Account - AEV, Inc. Sale | 2,000 | |
Level 1 | Forward Gasoline Purchase Contracts | ||
Liabilities: | ||
Derivative Liabilities | ||
Level 1 | Money Market and Mutual Funds | ||
Assets: | ||
Derivative Assets | 120 | |
Other Assets - Nonqualified Retirement Savings Plan | 550 | 593 |
Level 2 | ||
Assets: | ||
Total Assets | 7,854 | 8,014 |
Liabilities: | ||
Total Liabilities | 282 | 342 |
Level 2 | Forward Energy Contracts | ||
Assets: | ||
Derivative Assets | ||
Level 2 | Money Market Deposit Escrow | ||
Assets: | ||
Money Market Deposit Escrow Account - AEV, Inc. Sale | ||
Level 2 | Forward Gasoline Purchase Contracts | ||
Liabilities: | ||
Derivative Liabilities | 282 | 342 |
Level 2 | Corporate Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | 6,625 | 6,761 |
Level 2 | U.S. Government-Sponsored Enterprises' Debt Securities | ||
Assets: | ||
Investments - Held by Captive Insurance Company | 1,229 | 1,253 |
Level 3 | ||
Assets: | ||
Total Assets | 381 | 257 |
Liabilities: | ||
Total Liabilities | 11,285 | 13,888 |
Level 3 | Forward Energy Contracts | ||
Assets: | ||
Derivative Assets | 381 | 257 |
Liabilities: | ||
Derivative Liabilities | 11,285 | 13,888 |
Level 3 | Money Market Deposit Escrow | ||
Assets: | ||
Money Market Deposit Escrow Account - AEV, Inc. Sale | ||
Level 3 | Forward Gasoline Purchase Contracts | ||
Liabilities: | ||
Derivative Liabilities |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Changes in Level 3 forward energy contract derivative asset and liability fair valuations (Details 1) (Forward Energy Contracts, Level 3, USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Forward Energy Contracts | Level 3 | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Forward Energy Contracts - Fair Values Beginning of Period | ($13,631) | ($11,341) |
Less: Amounts Reversed on Settlement of Contracts Entered into in Prior Periods | 3,386 | 1,160 |
Net Changes in Fair Value of Contracts Entered into in Prior Periods | -368 | 3,498 |
Cumulative Fair Value Adjustments of Contracts Entered into in Prior Years at End of Period | -10,613 | -6,683 |
Net (Loss) Gain Recognized as Regulatory Assets on Contract Entered into in Period | -291 | 40 |
Forward Energy Contracts - Net Derivative Liability Fair Values End of Period | ($10,904) | ($6,643) |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Inventories (Details 2) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Finished Goods | $27,607 | $27,998 |
Work in Process | 9,894 | 10,628 |
Raw Material, Fuel and Supplies | 47,014 | 46,577 |
Total Inventories | $84,515 | $85,203 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Summary of changes to goodwill by business segment (Details 3) (USD $) | 3 Months Ended |
In Thousands, unless otherwise specified | Mar. 31, 2015 |
Goodwill [Line Items] | |
Gross Balance December 31, 2014 | $31,488 |
Accumulated Impairments | |
Goodwill [Roll Forward] | |
Balance (net of impairments) December 31, 2014 | 31,488 |
Adjustments to Goodwill in 2015 | |
Balance (net of impairments) March 31,2015 | 31,488 |
Manufacturing | |
Goodwill [Line Items] | |
Gross Balance December 31, 2014 | 12,186 |
Accumulated Impairments | |
Goodwill [Roll Forward] | |
Balance (net of impairments) December 31, 2014 | 12,186 |
Adjustments to Goodwill in 2015 | |
Balance (net of impairments) March 31,2015 | 12,186 |
Plastics | |
Goodwill [Line Items] | |
Gross Balance December 31, 2014 | 19,302 |
Accumulated Impairments | |
Goodwill [Roll Forward] | |
Balance (net of impairments) December 31, 2014 | 19,302 |
Adjustments to Goodwill in 2015 | |
Balance (net of impairments) March 31,2015 | $19,302 |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies - Components of intangible assets (Details 4) (USD $) | 3 Months Ended | 12 Months Ended |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 17,556 | 17,450 |
Accumulated Amortization | 6,443 | 6,199 |
Net Carrying Amount | 11,113 | 11,251 |
Customer Relationships | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 16,811 | 16,811 |
Accumulated Amortization | 5,996 | 5,784 |
Net Carrying Amount | 10,815 | 11,027 |
Customer Relationships | Minimum | ||
Amortizable Intangible Assets: | ||
Amortization Periods | 57 months | 60 months |
Customer Relationships | Maximum | ||
Amortizable Intangible Assets: | ||
Amortization Periods | 157 months | 160 months |
Other Intangible Assets Including Contracts | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 639 | 639 |
Accumulated Amortization | 447 | 415 |
Net Carrying Amount | 192 | 224 |
Amortization Periods | 18 months | 21 months |
Emission Allowances | ||
Amortizable Intangible Assets: | ||
Gross Carrying Amount | 106 | |
Accumulated Amortization | ||
Net Carrying Amount | 106 |
Summary_of_Significant_Account8
Summary of Significant Accounting Policies - Amortization expense for intangible assets (Details 5) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Accounting Policies [Abstract] | ||
Amortization Expense - Intangible Assets | $244 | $244 |
Summary_of_Significant_Account9
Summary of Significant Accounting Policies - Estimated amortization expense for intangible assets (Details 6) (USD $) | Mar. 31, 2015 |
In Thousands, unless otherwise specified | |
Accounting Policies [Abstract] | |
2015 | $977 |
2016 | 945 |
2017 | 849 |
2018 | 849 |
2019 | $849 |
Recovered_Sheet1
Summary of Significant Accounting Policies - Reconciliation of OTP's emission allowances (Details 7) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Intangible Assets [Line Items] | ||
Emission Allowances Beginning Balance | $11,251 | |
Emission Allowances Ending Balance | 11,113 | 11,251 |
Emission Allowances | ||
Intangible Assets [Line Items] | ||
Emission Allowances Beginning Balance | ||
Allowances Purchased | 168 | |
Allowances Used | -62 | |
Emission Allowances Ending Balance | $106 |
Recovered_Sheet2
Summary of Significant Accounting Policies - Supplemental disclosure of cash flow information (Details 8) (USD $) | Mar. 31, 2015 | Mar. 31, 2014 | ||
In Thousands, unless otherwise specified | ||||
Noncash Investing Activities: | ||||
Accounts Payable Outstanding Related to Capital Additions | $32,838 | [1] | $22,244 | [1] |
Accounts Receivable Outstanding Related to Joint Plant Owner's Share of Capital Additions | $7,554 | [2] | $3,434 | [2] |
[1] | Amounts are included in cash used for capital expenditures in subsequent periods when payables are settled. | |||
[2] | Amounts are deducted from cash used for capital expenditures in subsequent periods when cash is received. |
Recovered_Sheet3
Summary of Significant Accounting Policies (Detail Textuals) (USD $) | 3 Months Ended |
In Thousands, unless otherwise specified | Mar. 31, 2015 |
Minimum | |
Significant Accounting Policies [Line Items] | |
Product warranty period (in years) | 1 year |
Maximum | |
Significant Accounting Policies [Line Items] | |
Product warranty period (in years) | 15 years |
Forward Electricity Contracts | Level 3 | |
Significant Accounting Policies [Line Items] | |
Electric inputs minimum deviation below active trade hub prices per megawatt-hour | 2.46 |
Electric inputs maximum deviation below active trading hub price per megawatt-hour | 8 |
Electric inputs weighted average price per megawatt-hour | 34.45 |
Forward Electricity Contracts | Power purchase contracts | Level 3 | |
Significant Accounting Policies [Line Items] | |
Percentage of offset by regulatory liabilities and assets of fuel clause adjustment treatment of fuel costs | 100.00% |
Net impact of recorded fair valuation gains or losses related to derivative contract | 0 |
Net income impact of future fair valuation adjustments of contracts | 0 |
Recovered_Sheet4
Summary of Significant Accounting Policies (Detail Textuals 1) (Coyote Creek Mining Company, L.L.C. (CCMC), Lignite Sales Agreement, Otter Tail Power Company, USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 |
Coyote Creek Mining Company, L.L.C. (CCMC) | Lignite Sales Agreement | Otter Tail Power Company | |
Significant Accounting Policies [Line Items] | |
Amortization period | 52 months |
Percentage of development period costs, development fees and capital charge incurred by CCMC | 35.00% |
Amount of development period costs, development fees and capital charges incurred by CCMC | $28.50 |
Maximum exposure to loss as a result of involvement with CCMC | $28.50 |
Segment_Information_Percent_of
Segment Information - Percent of sales revenue by country (Details) (Sales) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
United States of America | ||
Segment Reporting Information [Line Items] | ||
Percentage of sales revenue | 96.30% | 97.20% |
Mexico | ||
Segment Reporting Information [Line Items] | ||
Percentage of sales revenue | 3.00% | 2.20% |
Canada | ||
Segment Reporting Information [Line Items] | ||
Percentage of sales revenue | 0.60% | 0.50% |
All Other Countries (none individually greater than 0.05%) | ||
Segment Reporting Information [Line Items] | ||
Percentage of sales revenue | 0.10% | 0.10% |
Segment_Information_Informatio
Segment Information - Information on continuing operations for business segments (Details 1) (USD $) | 3 Months Ended | ||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | |||
Operating Revenue | $202,841 | $214,966 | |
Interest Charges | 7,743 | 6,595 | |
Income Taxes | 4,073 | 8,562 | |
Net Income | 17,935 | 21,430 | |
Identifiable Assets | 1,815,180 | 1,791,279 | |
Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Operating Revenue | -17 | -40 | |
Corporate and Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Interest Charges | 544 | 461 | |
Corporate | |||
Segment Reporting Information [Line Items] | |||
Income Taxes | -1,916 | -992 | |
Net Income | -2,701 | -1,230 | |
Identifiable Assets | 68,321 | 51,918 | |
Discontinued Operations | |||
Segment Reporting Information [Line Items] | |||
Net Income | 4,154 | -349 | |
Identifiable Assets | 33,171 | 48,657 | |
Electric | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Operating Revenue | 113,547 | 119,088 | |
Interest Charges | 6,121 | 5,079 | |
Income Taxes | 4,221 | 5,750 | |
Net Income | 13,178 | 16,653 | |
Identifiable Assets | 1,484,289 | 1,472,647 | |
Manufacturing | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Operating Revenue | 56,759 | 55,435 | |
Interest Charges | 832 | 808 | |
Income Taxes | 504 | 1,671 | |
Net Income | 1,184 | 2,896 | |
Identifiable Assets | 139,143 | 130,701 | |
Plastics | Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Operating Revenue | 32,552 | 40,483 | |
Interest Charges | 246 | 247 | |
Income Taxes | 1,264 | 2,133 | |
Net Income | 2,120 | 3,460 | |
Identifiable Assets | $90,256 | $87,356 |
Segment_Information_Detail_Tex
Segment Information (Detail Textuals) | 3 Months Ended |
Mar. 31, 2015 | |
Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 3 |
Rate_and_Regulatory_Matters_Su
Rate and Regulatory Matters - Summary of revenues recorded under rate riders (Details 1) (USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | ||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | $202,841 | $214,966 | ||
Otter Tail Power Company | Minnesota | Transmission Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 1,615 | 2,304 | ||
Otter Tail Power Company | Minnesota | Environmental Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 2,557 | 1,763 | ||
Otter Tail Power Company | Minnesota | Conservation Improvement Program Costs and Incentives | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 1,928 | [1] | 1,521 | [1] |
Otter Tail Power Company | North Dakota | Renewable Resource Adjustment | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 1,883 | 1,435 | ||
Otter Tail Power Company | North Dakota | Transmission Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 1,936 | 1,514 | ||
Otter Tail Power Company | North Dakota | Environmental Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 2,156 | 1,522 | ||
Otter Tail Power Company | North Dakota | Big Stone II Project Costs | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 361 | |||
Otter Tail Power Company | South Dakota | Transmission Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | 363 | 346 | ||
Otter Tail Power Company | South Dakota | Environmental Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Revenues Recorded under Rate Riders | $504 | |||
[1] | Includes MNCIP costs recovered in base rates. |
Rate_and_Regulatory_Matters_De
Rate and Regulatory Matters (Detail Textuals) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2011 | Mar. 31, 2014 |
mi | mi | ||
Kv | |||
Otter Tail Power Company | |||
Regulatory Matters [Line Items] | |||
Increase In reagent costs and emission allowances | $4.10 | ||
Reagent costs | 3.6 | ||
Emission allowances | 0.5 | ||
Otter Tail Power Company | Minnesota | |||
Regulatory Matters [Line Items] | |||
Percentage of reagent costs and emission allowances shared | 50.00% | ||
Otter Tail Power Company | North Dakota | |||
Regulatory Matters [Line Items] | |||
Percentage of reagent costs and emission allowances shared | 40.00% | ||
Otter Tail Power Company | South Dakota | |||
Regulatory Matters [Line Items] | |||
Percentage of reagent costs and emission allowances shared | 10.00% | ||
Otter Tail Power Company | Big Stone South - Brookings MVP | Federal Energy Regulatory Commission | |||
Regulatory Matters [Line Items] | |||
Expanded capacity of projects | 345 | ||
Extended distance of transmission line | 70 | ||
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | |||
Regulatory Matters [Line Items] | |||
Expanded capacity of projects | 345 | ||
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Minimum | |||
Regulatory Matters [Line Items] | |||
Extended distance of transmission line | 160 | ||
Otter Tail Power Company | Big Stone South - Ellendale MVP | Federal Energy Regulatory Commission | Maximum | |||
Regulatory Matters [Line Items] | |||
Extended distance of transmission line | 170 | ||
Big Stone AQCS Project BART - compliant AQCS | |||
Regulatory Matters [Line Items] | |||
Current projected cost | 384 | ||
Big Stone AQCS Project BART - compliant AQCS | Otter Tail Power Company | |||
Regulatory Matters [Line Items] | |||
Current projected cost | 207 | ||
Percentage of projected cost | 53.90% | ||
Construction expenditures | $174.90 | ||
Capacity Expansion 2020 | Otter Tail Power Company | Brookings Project | |||
Regulatory Matters [Line Items] | |||
Extended distance of transmission line | 250 |
Rate_and_Regulatory_Matters_De1
Rate and Regulatory Matters (Detail Textuals 1) (USD $) | 3 Months Ended | 0 Months Ended | 1 Months Ended | ||||
Mar. 31, 2015 | Feb. 07, 2013 | Dec. 31, 2014 | Jul. 30, 2014 | Jul. 31, 2014 | Apr. 25, 2011 | Sep. 26, 2014 | |
Project | |||||||
Conservation Improvement Program | Fiscal Year 2014 | |||||||
Regulatory Matters [Line Items] | |||||||
Financial incentives recognized during period | $3,000,000 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 | |||||||
Regulatory Matters [Line Items] | |||||||
Financial incentive request approved | 4,000,000 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2013 To 2015 | |||||||
Regulatory Matters [Line Items] | |||||||
Lower Estimated Incentives | 0.09 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Conservation Improvement Program | Fiscal Year 2014 To 2016 | |||||||
Regulatory Matters [Line Items] | |||||||
Lower Estimated Incentives | 0.07 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Transmission Cost Recovery Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Number of additional projects approved | 3 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | Environmental Cost Recovery Rider | |||||||
Regulatory Matters [Line Items] | |||||||
Annual revenue requirement | 9,800,000 | 6,100,000 | 10,200,000 | ||||
Annual increase in revenue requirement | 4,100,000 | ||||||
Otter Tail Power Company | Minnesota Public Utilities Commission | 2010 General Rate Case | |||||||
Regulatory Matters [Line Items] | |||||||
General rate revenue increase approved | $5,000,000 | ||||||
Percentage of increase in base rate revenue approved by rate authority | 1.60% | ||||||
Public utilities allowed rate of return prior to approval of increase in base rate | 8.33% | ||||||
Public utilities allowed rate of return 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% |
Rate_and_Regulatory_Matters_De2
Rate and Regulatory Matters (Detail Textuals 2) (Otter Tail Power Company, North Dakota Public Service Commission, USD $) | 1 Months Ended | 0 Months Ended | 1 Months Ended | |
Aug. 29, 2014 | Mar. 12, 2014 | Mar. 31, 2014 | Nov. 25, 2009 | |
Big Stone II Cost Recovery | ||||
Regulatory Matters [Line Items] | ||||
Regulators jurisdictional share of transmission costs | $100,000 | |||
Renewable Resource Cost Recovery Rider | ||||
Regulatory Matters [Line Items] | ||||
Percentage of reduction in the NDRRA | 13.50% | |||
Environmental Cost Recovery Rider | Minimum | ||||
Regulatory Matters [Line Items] | ||||
Percentage of ECR rider rate | 4.32% | |||
Environmental Cost Recovery Rider | Maximum | ||||
Regulatory Matters [Line Items] | ||||
Percentage of ECR rider rate | 7.53% | |||
2010 General Rate Case | ||||
Regulatory Matters [Line Items] | ||||
Revenue increase approved by rate authority | $3,600,000 | |||
Percentage of increase in base rate revenue approved by rate authority | 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_De3
Rate and Regulatory Matters (Detail Textuals 3) (Otter Tail Power Company, USD $) | 1 Months Ended | 0 Months Ended | 1 Months Ended | |
Apr. 21, 2011 | Feb. 12, 2015 | Nov. 30, 2013 | Mar. 31, 2015 | |
South Dakota Public Utilities Commission | 2010 General Rate Case | ||||
Regulatory Matters [Line Items] | ||||
Revenue increase approved by rate authority | 643,000 | |||
Percentage of increase in base rate revenue approved by rate authority | 2.32% | |||
South Dakota Public Utilities Commission | 2010 General Rate Case | Big Stone II Cost Recovery | ||||
Regulatory Matters [Line Items] | ||||
Public utilities allowed rate of return subsequent to approval of increase in base rate | 8.50% | |||
Federal Energy Regulatory Commission | ||||
Regulatory Matters [Line Items] | ||||
Proposed reduced return on equity used in transmission rates | 8.67% | 9.15% | ||
Estimated liability of refund obligation | $600,000 | |||
Current return on equity used in transmission rates | 12.38% |
Regulatory_Assets_and_Liabilit2
Regulatory Assets and Liabilities - Amount of regulatory assets and liabilities recorded on consolidated balance sheet (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | ||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | $20,352 | $25,273 | ||
Regulatory Liability - Current | 2,744 | 1,158 | ||
Net Regulatory Assets Position - Current | 17,608 | 24,115 | ||
Regulatory Assets - Long-Term | 127,368 | 129,868 | ||
Regulatory Liabilities - Long-Term | 77,851 | 77,013 | ||
Net Regulatory Assets (Liability) Position - Long-Term | 49,517 | 52,855 | ||
Regulatory Assets - Total | 147,720 | 155,141 | ||
Regulatory Liabilities - Total | 80,595 | 78,171 | ||
Net Regulatory Asset Position - Total | 67,125 | 76,970 | ||
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 7,465 | [1] | 7,464 | [1] |
Regulatory Assets - Long-Term | 99,659 | [1] | 101,526 | [1] |
Regulatory Assets - Total | 107,124 | [1] | 108,990 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | see below | [1] | see below | [1] |
Deferred Marked-to-Market Loss | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 2,059 | [1] | 4,492 | [1] |
Regulatory Assets - Long-Term | 9,226 | [1] | 9,396 | [1] |
Regulatory Assets - Total | 11,285 | [1] | 13,888 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | 69 months | [1] | 72 months | [1] |
Conservation Improvement Program Costs and Incentives | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 3,815 | [2] | 5,843 | [2] |
Regulatory Assets - Long-Term | 3,511 | [2] | 2,500 | [2] |
Regulatory Assets - Total | 7,326 | [2] | 8,343 | [2] |
Regulatory Assets - Remaining Recovery/Refund Period | 27 months | [2] | 18 months | [2] |
Accumulated ARO Accretion/Depreciation Adjustment | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | [1] | [1] | ||
Regulatory Assets - Long-Term | 5,305 | [1] | 5,190 | [1] |
Regulatory Assets - Total | 5,305 | [1] | 5,190 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | asset lives | [1] | asset lives | [1] |
Big Stone II Unrecovered Project Costs - Minnesota | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 601 | [1] | 592 | [1] |
Regulatory Assets - Long-Term | 3,086 | [1] | 3,207 | [1] |
Regulatory Assets - Total | 3,687 | [1] | 3,799 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | 93 months | [1] | 96 months | [1] |
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 2,140 | [1] | 2,585 | [1] |
Regulatory Assets - Long-Term | 636 | [1] | 807 | [1] |
Regulatory Assets - Total | 2,776 | [1] | 3,392 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | 24 months | 24 months | [1] | |
Debt Reacquisition Premiums | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 351 | [1] | 351 | [1] |
Regulatory Assets - Long-Term | 1,802 | [1] | 1,890 | [1] |
Regulatory Assets - Total | 2,153 | [1] | 2,241 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | 210 months | [1] | 213 months | [1] |
Deferred Income Taxes | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | [1] | [1] | ||
Regulatory Liability - Current | ||||
Regulatory Assets - Long-Term | 1,461 | [1] | 2,086 | [1] |
Regulatory Liabilities - Long-Term | 1,447 | 1,550 | ||
Regulatory Assets - Total | 1,461 | [1] | 2,086 | [1] |
Regulatory Liabilities - Total | 1,447 | 1,550 | ||
Regulatory Assets - Remaining Recovery/Refund Period | asset lives | [1] | asset lives | [1] |
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | ||
North Dakota Environmental Cost Recovery Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 706 | [2] | ||
Regulatory Assets - Long-Term | [2] | |||
Regulatory Assets - Total | 706 | [2] | ||
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | ||
Minnesota Environmental Cost Recovery Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 186 | [2] | ||
Regulatory Assets - Long-Term | [2] | |||
Regulatory Assets - Total | 186 | [2] | ||
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | ||
Minnesota Renewable Resource Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | [2] | [2] | ||
Regulatory Assets - Long-Term | 68 | [2] | 68 | [2] |
Regulatory Assets - Total | 68 | [2] | 68 | [2] |
Regulatory Assets - Remaining Recovery/Refund Period | see below | [2] | see below | [2] |
Accumulated Reserve for Estimated Removal Costs - Net of Salvage | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | ||||
Regulatory Liabilities - Long-Term | 75,220 | 74,237 | ||
Regulatory Liabilities - Total | 75,220 | 74,237 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | asset lives | asset lives | ||
Deferred Marked-to-Market Gains | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 204 | |||
Regulatory Liabilities - Long-Term | 177 | 257 | ||
Regulatory Liabilities - Total | 381 | 257 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 58 months | 67 months | ||
North Dakota Renewable Resource Rider Accrued Refund | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 1,803 | 933 | ||
Regulatory Liabilities - Long-Term | 85 | |||
Regulatory Liabilities - Total | 1,803 | 1,018 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | 15 months | ||
Revenue for Rate Case expenses Subject to Refund - Minnesota | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | ||||
Regulatory Liabilities - Long-Term | 908 | 784 | ||
Regulatory Liabilities - Total | 908 | 784 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | see below | see below | ||
Big Stone II Over Recovered Project Costs - North Dakota | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 111 | 147 | ||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | 111 | 147 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 9 months | 12 months | ||
Big Stone II Unrecovered Project Costs - South Dakota | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 100 | [2] | 100 | [2] |
Regulatory Assets - Long-Term | 718 | [2] | 743 | [2] |
Regulatory Assets - Total | 818 | [2] | 843 | [2] |
Regulatory Assets - Remaining Recovery/Refund Period | 98 months | [2] | 101 months | [2] |
North Dakota Renewable Resource Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | [2] | |||
Regulatory Assets - Long-Term | 61 | [2] | ||
Regulatory Assets - Total | 61 | [2] | ||
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | ||
Deferred Gain on Sale of Utility Property - Minnesota Portion | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 6 | 6 | ||
Regulatory Liabilities - Long-Term | 99 | 100 | ||
Regulatory Liabilities - Total | 105 | 106 | ||
Regulatory Liabilities - Remaining Recovery/Refund Period | 225 months | 228 months | ||
Recoverable Fuel and Purchased Power Costs | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 1,249 | [1] | 1,114 | [1] |
Regulatory Assets - Long-Term | [1] | [1] | ||
Regulatory Assets - Total | 1,249 | [1] | 1,114 | [1] |
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [1] | 12 months | [1] |
South Dakota - Nonasset-Based Margin Sharing Excess | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 24 | |||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | 24 | |||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | |||
Minnesota Transmission Cost Recovery Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 2,152 | [2] | 943 | [2] |
Regulatory Assets - Long-Term | 1,835 | [2] | 2,455 | [2] |
Regulatory Assets - Total | 3,987 | [2] | 3,398 | [2] |
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | 24 months | [2] |
North Dakota Transmission Cost Recovery Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 420 | [2] | 859 | [2] |
Regulatory Assets - Long-Term | [2] | [2] | ||
Regulatory Assets - Total | 420 | [2] | 859 | [2] |
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | 12 months | [2] |
Minnesota Environmental Cost Recovery Rider Accrued Refund | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 451 | |||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | 451 | |||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | |||
South Dakota Environmental Cost Recovery Rider Accrued Revenues | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Asset - Current | 38 | [2] | ||
Regulatory Assets - Long-Term | [2] | |||
Regulatory Assets - Total | 38 | [2] | ||
Regulatory Assets - Remaining Recovery/Refund Period | 12 months | [2] | ||
South Dakota Transmission Cost Recovery Rider Accrued Refund | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 48 | 48 | ||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | 48 | 48 | ||
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 Liability - Current | 35 | |||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | 35 | |||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | |||
South Dakota Environmental Cost Recovery Rider Accrued Refund | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||
Regulatory Liability - Current | 86 | |||
Regulatory Liabilities - Long-Term | ||||
Regulatory Liabilities - Total | $86 | |||
Regulatory Liabilities - Remaining Recovery/Refund Period | 12 months | |||
[1] | Costs subject to recovery without a rate of return. | |||
[2] | Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return. |
Regulatory_Assets_and_Liabilit3
Regulatory Assets and Liabilities (Detail Textuals) (Debt Reacquisition Premiums) | 3 Months Ended |
Mar. 31, 2015 | |
Debt Reacquisition Premiums | |
Schedule of Regulatory Assets and Liabilities [Line Items] | |
Regulatory assets - long term, remaining recovery/refund period | 210 months |
Forward_Contracts_Classified_a2
Forward Contracts Classified as Derivatives - Effect of marking to market forward contracts for purchase and sale of electricity and location and fair value amounts of related derivatives (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||||
Derivatives, Fair Value [Line Items] | ||||
Regulatory Asset - Current | $20,352 | $25,273 | ||
Regulatory Assets - Long-Term | 127,368 | 129,868 | ||
Current Liability - Marked-to-Market Loss | -11,567 | -14,230 | ||
Regulatory Liability - Current | -2,744 | -1,158 | ||
Regulatory Liabilities - Long-Term | -77,851 | -77,013 | ||
Forward Electricity Contracts | ||||
Derivatives, Fair Value [Line Items] | ||||
Current Asset - Marked-to-Market Gain | 381 | 257 | ||
Total Assets | 11,666 | 14,145 | ||
Current Liability - Marked-to-Market Loss | -11,285 | -13,888 | ||
Total Liabilities | -11,666 | -14,145 | ||
Net Fair Value of Marked-to-Market Energy Contracts | 39 | 115 | ||
Forward Electricity Contracts | Deferred Marked-to-Market Loss | ||||
Derivatives, Fair Value [Line Items] | ||||
Regulatory Asset - Current | 2,059 | 4,492 | ||
Regulatory Assets - Long-Term | 9,226 | 9,396 | ||
Forward Electricity Contracts | Deferred Marked-to-Market Gain | ||||
Derivatives, Fair Value [Line Items] | ||||
Regulatory Liability - Current | -204 | |||
Regulatory Liabilities - Long-Term | ($177) | ($257) |
Forward_Contracts_Classified_a3
Forward Contracts Classified as Derivatives - Change in consolidated balance sheet location and fair values of forward contracts for purchase and sale of electricity (Details 1) (Forward Electricity Contracts, USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Forward Electricity Contracts | ||
Derivatives Fair Value [Roll Forward] | ||
Cumulative Fair Value Adjustments Included in Earnings - Beginning of Year | $115 | |
Less: Amounts Realized on Settlement of Contracts Entered into in Prior Periods | -72 | |
Changes in Fair Value of Contracts Entered into in Prior Periods | -43 | |
Cumulative Fair Value Adjustments in Earnings of Contracts Entered into in Prior Years at End of Period | ||
Changes in Fair Value of Contracts Entered into in Current Period | 39 | |
Cumulative Fair Value Adjustments Included in Earnings - End of Period | $39 |
Forward_Contracts_Classified_a4
Forward Contracts Classified as Derivatives - Realized and unrealized net (losses)/gains on forward energy contracts included in electric operating revenues (Details 2) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Net Loss on Forward Electric Energy Contracts | ($4) |
Forward_Contracts_Classified_a5
Forward Contracts Classified as Derivatives - Amount of derivative asset and derivative liability balances subject to legally enforceable netting arrangements (Details 3) (Legally enforceable netting arrangements, USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Legally enforceable netting arrangements | ||
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items] | ||
Derivative assets subject to legally enforceable netting arrangements | $381 | $257 |
Derivative liabilities subject to legally enforceable netting arrangements | -11,567 | -14,230 |
Net balance subject to legally enforceable netting arrangements | ($11,186) | ($13,973) |
Forward_Contracts_Classified_a6
Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Details 4) (Otter Tail Power Company, USD $) | Mar. 31, 2015 | Dec. 31, 2014 | ||
In Thousands, unless otherwise specified | ||||
Otter Tail Power Company | ||||
Current Liability - Marked-to-Market Loss (in thousands) | ||||
Loss Contracts Covered by Deposited Funds or Letters of Credit | $282 | $45 | ||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | 11,285 | [1] | 13,888 | [1] |
Loss Contracts with No Ratings Triggers or Deposit Requirements | 297 | |||
Total Current Liability - Marked-to-Market Loss | $11,567 | $14,230 | ||
[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 $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631 |
Forward_Contracts_Classified_a7
Forward Contracts Classified as Derivatives - Breakdown of OTP's credit risk standing on forward energy contracts in marked-to-market loss positions (Parenthetical) (Details) (Otter Tail Power Company, USD $) | Mar. 31, 2015 | Dec. 31, 2014 | ||
In Thousands, unless otherwise specified | ||||
Otter Tail Power Company | ||||
Credit Derivatives [Line Items] | ||||
Contracts Requiring Cash Deposits if OTP's Credit Falls Below Investment Grade | $11,285 | [1] | $13,888 | [1] |
Offsetting Gains with Counterparties under Master Netting Agreements | -381 | -257 | ||
Reporting Date Deposit Requirement if Credit Risk Feature Triggered | $10,904 | $13,631 | ||
[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 $ 11,285 $ 13,888 Offsetting Gains with Counterparties under Master Netting Agreements (381 ) (257 ) Reporting Date Deposit Requirement if Credit Risk Feature Triggered $ 10,904 $ 13,631 |
Reconciliation_of_Common_Share2
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, Beginning of Period | $572,766 | |
Common Stock Issuances, Net of Expenses | 7,522 | |
Common Stock Retirements | -1,239 | |
Net Income | 17,935 | 21,430 |
Other Comprehensive Income | 141 | |
Tax Benefit - Stock Compensation | 24 | |
Employee Stock Incentive Plans Expense | 623 | |
Common Dividends ($0.3075 per share) | -11,498 | |
Balance, End of Period | 586,274 | |
Common Shares | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, Beginning of Period | 186,090 | |
Common Stock Issuances, Net of Expenses | 1,220 | |
Common Stock Retirements | -195 | |
Balance, End of Period | 187,115 | |
Premium On Common Shares | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, Beginning of Period | 278,436 | |
Common Stock Issuances, Net of Expenses | 6,302 | |
Common Stock Retirements | -1,044 | |
Tax Benefit - Stock Compensation | 24 | |
Employee Stock Incentive Plans Expense | 623 | |
Balance, End of Period | 284,341 | |
Retained Earnings | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, Beginning of Period | 112,903 | |
Net Income | 17,935 | |
Common Dividends ($0.3075 per share) | -11,498 | |
Balance, End of Period | 119,340 | |
Accumulated Other Comprehensive Income/(Loss) | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Balance, Beginning of Period | -4,663 | |
Other Comprehensive Income | 141 | |
Balance, End of Period | ($4,522) |
Reconciliation_of_Common_Share3
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Parenthetical) (Details) (USD $) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||
Dividends Declared Per Common Share (in dollars per share) | $0.31 | $0.30 |
Reconciliation_of_Common_Share4
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share - Reconciliation of common shares outstanding (Details 1) | 3 Months Ended |
Mar. 31, 2015 | |
Stockholders Equity and Earnings Per Share [Abstract] | |
Common Shares Outstanding, December 31, 2014 | 37,218,053 |
Issuances: | |
Executive Stock Performance Awards (2012-2014 shares earned) | 89,991 |
Automatic Dividend Reinvestment and Share Purchase Plan: | |
Dividends Reinvested | 42,518 |
Cash Invested | 16,553 |
At-the-Market Offering | 38,160 |
Employee Stock Purchase Plan: | |
Cash Invested | 19,993 |
Dividends Reinvested | 5,985 |
Employee Stock Ownership Plan | 21,137 |
Stock Options Exercised | 9,000 |
Vesting of Restricted Stock Units | 700 |
Retirements: | |
Shares Withheld for Individual Income Tax Requirements | -39,131 |
Common Shares Outstanding, March 31, 2015 | 37,422,959 |
Reconciliation_of_Common_Share5
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) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Stockholders Equity and Earnings Per Share [Abstract] | ||
Weighted Average Common Shares Outstanding - Basic | 37,243,118 | 36,240,350 |
Plus: | ||
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers | 229,100 | 131,000 |
Nonvested Restricted Shares | 83,330 | 90,798 |
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees | 70,900 | 55,655 |
Shares Expected to be Issued Under the Deferred Compensation Program for Directors | 40,462 | 39,197 |
Potentially Dilutive Stock Options | 3,750 | 18,050 |
Less: | ||
Shares Equivalent of Tax Savings from Issuance of Dilutive Shares | -169,842 | -127,709 |
Shares Equivalent of Proceeds from Exercise of Potentially Dilutive Stock Options | -2,937 | -15,426 |
Total Dilutive Shares | 254,763 | 191,565 |
Weighted Average Common Shares Outstanding - Diluted | 37,497,881 | 36,431,915 |
Reconciliation_of_Common_Share6
Reconciliation of Common Shareholders' Equity, Common Shares and Earnings Per Share (Detail Textuals) (USD $) | 3 Months Ended |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 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 |
Distribution Agreement | J.P. Morgan Securities Inc. (JPMS) | |
Stockholders Equity Note [Line Items] | |
Agreement To Sell Shares Value | $75 |
ShareBased_Payments_Stock_Ince
Share-Based Payments - Stock Incentive Awards (Details) (USD $) | 3 Months Ended |
Mar. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 116,250 |
Stock Performance Awards | Executive Officers | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 77,500 |
Weighted Average Grant-Date Fair Value per Award | 26.99 |
Vesting Date | 31-Dec-17 |
Restricted Stock Units | Executive Officer Two | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 20,900 |
Weighted Average Grant-Date Fair Value per Award | 31.675 |
Vesting Percentage | 25.00% |
Vesting Date | 6-Feb-19 |
Restricted Stock Units | Executive Officer Three | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares/Units Granted | 6,400 |
Weighted Average Grant-Date Fair Value per Award | 31.675 |
Vesting Percentage | 100.00% |
Vesting Date | 6-Feb-20 |
ShareBased_Payments_Amounts_of
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | $1,643 | $884 |
Employee Stock Purchase Plan | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 49 | 42 |
Restricted Stock | Directors | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 98 | 123 |
Restricted Stock | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 157 | 135 |
Restricted Stock Units (RSUs) | Employees | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 66 | 58 |
Restricted Stock Units (RSUs) | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | 253 | |
Stock Performance Awards | Executive Officers | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock compensation expense | $1,020 | $526 |
ShareBased_Payments_Amounts_of1
Share-Based Payments - Amounts of compensation expense recognized under stock-based payment programs (Parentheticals) (Details) (Employee Stock Purchase Plan) | 3 Months Ended |
Mar. 31, 2015 | |
Employee Stock Purchase Plan | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock compensation expense, discount rate | 15.00% |
ShareBased_Payments_Detail_Tex
Share-Based Payments (Detail Textuals) | 3 Months Ended |
Mar. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Targeted aggregate common shares award | 116,250 |
Stock Performance Awards | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Period specified for average adjusted return | 3 years |
Stock Performance Awards | Executive Officers | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Target award total shareholder return/equity component | 51,667 |
Targeted aggregate common shares award | 77,500 |
Stock Performance Awards | Executive Officers | Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Percentage of target amount as actual payment | 150.00% |
Stock Performance Awards | Executive Officers | Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Percentage of target amount as actual payment | 0.00% |
Stock Performance Awards Two | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Target award total shareholder return/equity component | 25,833 |
ShareBased_Payments_Detail_Tex1
Share-Based Payments (Detail Textuals 1) (USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 |
Share-Based Compensation Arrangement By Share-Based Payment Award [Line Items] | |
Unrecognized compensation expense related to stock-based compensation | $2.80 |
Weighted-average period of amortization | 2 years 3 months 18 days |
Retained_Earnings_Restriction_
Retained Earnings Restriction (Detail Textuals) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Retained Earnings Restriction [Line Items] | ||
Total Capitalization | $1,084,711 | $1,071,255 |
OTP | ||
Retained Earnings Restriction [Line Items] | ||
Equity to total capitalization ratio | 50.70% | |
Total Capitalization | $987,000 | |
OTP | Minimum | ||
Retained Earnings Restriction [Line Items] | ||
Required equity-to-total-capitalization ratio to limit dividend payment | 45.00% | |
OTP | Maximum | ||
Retained Earnings Restriction [Line Items] | ||
Required equity-to-total-capitalization ratio to limit dividend payment | 55.00% |
Commitments_and_Contingencies_
Commitments and Contingencies (Detail Textuals) (Otter Tail Power Company, USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Apr. 30, 2015 |
Commitments and Contingencies Disclosure [Line Items] | |||
Amount of reduction in revenue and liability | $0.60 | ||
Capacity and Energy Requirements | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | 2.9 | ||
Contracts expiration year | 2039 | ||
Coal Purchase Commitments | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | 10 | ||
Contracts expiration year | 2015, 2016, 2017 and 2040 | ||
Loss contingency, range of possible loss, maximum | 5 | ||
Construction Programs | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | 106.1 | 106.6 | |
Subsequent event | |||
Commitments and Contingencies Disclosure [Line Items] | |||
Commitment under contracts aggregate amount | $2.80 |
ShortTerm_and_LongTerm_Borrowi2
Short-Term and Long-Term Borrowings - Status of lines of credit (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Line of Credit Facility [Line Items] | ||
Line Limit | $320,000 | |
In Use | 48,652 | |
Restricted due to Outstanding Letters of Credit | 755 | |
Available | 270,593 | 308,312 |
Otter Tail Corporation Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 150,000 | |
In Use | 40,846 | |
Restricted due to Outstanding Letters of Credit | 195 | |
Available | 108,959 | 138,872 |
OTP Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Line Limit | 170,000 | |
In Use | 7,806 | |
Restricted due to Outstanding Letters of Credit | 560 | |
Available | $161,634 | $169,440 |
ShortTerm_and_LongTerm_Borrowi3
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Details 1) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Debt Instrument [Line Items] | ||
Short-Term Debt | $48,652 | $10,854 |
Long-Term Debt | 498,641 | 498,691 |
Less: Current Maturities | 204 | 201 |
Unamortized Debt Discount | 1 | |
Total Long-Term Debt | 498,437 | 498,489 |
Total Short-Term and Long-Term Debt (with current maturities) | 547,293 | 509,544 |
9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 52,330 | 52,330 |
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 | 237 | 256 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 1,074 | 1,105 |
OTP | ||
Debt Instrument [Line Items] | ||
Short-Term Debt | 7,806 | |
Long-Term Debt | 445,000 | 445,000 |
Less: Current Maturities | ||
Unamortized Debt Discount | ||
Total Long-Term Debt | 445,000 | 445,000 |
Total Short-Term and Long-Term Debt (with current maturities) | 452,806 | 445,000 |
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 | 40,846 | 10,854 |
Long-Term Debt | 53,641 | 53,691 |
Less: Current Maturities | 204 | 201 |
Unamortized Debt Discount | 1 | |
Total Long-Term Debt | 53,437 | 53,489 |
Total Short-Term and Long-Term Debt (with current maturities) | 94,487 | 64,544 |
Otter Tail Corporation | 9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 52,330 | 52,330 |
Otter Tail Corporation | North Dakota Development Note, 3.95%, due April 1, 2018 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | 237 | 256 |
Otter Tail Corporation | Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt | $1,074 | $1,105 |
ShortTerm_and_LongTerm_Borrowi4
Short-Term and Long-Term Borrowings - Breakdown of assignment of consolidated short-term and long-term debt outstanding (Parentheticals) (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2015 | Dec. 31, 2014 | |
9.000% Notes, due December 15, 2016 | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 9.00% | 9.00% |
Long-Term Debt, Due Date | 15-Dec-16 | 15-Dec-16 |
9.000% Notes, due December 15, 2016 | Otter Tail Corporation | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 9.00% | 9.00% |
Long-Term Debt, Due Date | 15-Dec-16 | 15-Dec-16 |
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 | 20-Aug-17 | 20-Aug-17 |
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.95% | 5.95% |
Long-Term Debt, Due Date | 20-Aug-17 | 20-Aug-17 |
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 | 1-Dec-21 | 1-Dec-21 |
Senior Unsecured Notes 4.63%, due December 1, 2021 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.63% | 4.63% |
Long-Term Debt, Due Date | 1-Dec-21 | 1-Dec-21 |
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 | 20-Aug-22 | 20-Aug-22 |
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.15% | 6.15% |
Long-Term Debt, Due Date | 20-Aug-22 | 20-Aug-22 |
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 | 20-Aug-27 | 20-Aug-27 |
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.37% | 6.37% |
Long-Term Debt, Due Date | 20-Aug-27 | 20-Aug-27 |
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 | 27-Feb-29 | 27-Feb-29 |
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 4.68% | 4.68% |
Long-Term Debt, Due Date | 27-Feb-29 | 27-Feb-29 |
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 | 20-Aug-37 | 20-Aug-37 |
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 6.47% | 6.47% |
Long-Term Debt, Due Date | 20-Aug-37 | 20-Aug-37 |
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 | 27-Feb-44 | 27-Feb-44 |
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044 | OTP | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 5.47% | 5.47% |
Long-Term Debt, Due Date | 27-Feb-44 | 27-Feb-44 |
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 | 1-Apr-18 | 1-Apr-18 |
North Dakota Development Note, 3.95%, due April 1, 2018 | Otter Tail Corporation | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 3.95% | 3.95% |
Long-Term Debt, Due Date | 1-Apr-18 | 1-Apr-18 |
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 | 18-Mar-21 | 18-Mar-21 |
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021 | Otter Tail Corporation | ||
Debt Instrument [Line Items] | ||
Long-Term Debt, Interest Rate | 2.54% | 2.54% |
Long-Term Debt, Due Date | 18-Mar-21 | 18-Mar-21 |
Pension_Plan_and_Other_Postret2
Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Details) (USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | ||
Pension Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service Cost - Benefit Earned During the Period | $1,500 | $1,175 | ||
Interest Cost on Projected Benefit Obligation | 3,325 | 3,285 | ||
Expected Return on Assets | -4,600 | -4,187 | ||
Amortization of Prior-Service Cost: | ||||
From Regulatory Asset | 47 | 64 | ||
From Other Comprehensive Income | 1 | [1] | 2 | [1] |
Amortization of Net Actuarial Loss: | ||||
From Regulatory Asset | 1,633 | 868 | ||
From Other Comprehensive Income | 40 | [1] | 23 | [1] |
Net Periodic Pension Cost | 1,946 | 1,230 | ||
Executive Survivor and Supplemental Retirement Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service Cost - Benefit Earned During the Period | 47 | 13 | ||
Interest Cost on Projected Benefit Obligation | 381 | 380 | ||
Amortization of Prior-Service Cost: | ||||
From Regulatory Asset | 4 | 5 | ||
From Other Comprehensive Income | 10 | [2] | 13 | [2] |
Amortization of Net Actuarial Loss: | ||||
From Regulatory Asset | 83 | 35 | ||
From Other Comprehensive Income | 151 | [3] | 12 | [3] |
Net Periodic Pension Cost | 676 | 458 | ||
Postretirement Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Service Cost - Benefit Earned During the Period | 375 | 315 | ||
Interest Cost on Projected Benefit Obligation | 550 | 558 | ||
Amortization of Prior-Service Cost: | ||||
From Regulatory Asset | 51 | 51 | ||
From Other Comprehensive Income | 1 | [1] | 1 | [1] |
Amortization of Net Actuarial Loss: | ||||
From Regulatory Asset | 48 | |||
From Other Comprehensive Income | 1 | [1] | [1] | |
Net Periodic Pension Cost | 1,026 | 925 | ||
Effect of Medicare Part D Subsidy | ($450) | ($308) | ||
[1] | Corporate cost included in Other Nonelectric Expenses. | |||
[2] | Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8 | |||
[3] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 ) |
Pension_Plan_and_Other_Postret3
Pension Plan and Other Postretirement Benefits - Components of net periodic pension benefit cost (Parentheticals) (Details) (Executive Survivor and Supplemental Retirement Plan, USD $) | 3 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | ||
Defined Benefit Plan Disclosure [Line Items] | ||||
Amortization of Prior-Service Cost - From Other Comprehensive Income | $10 | [1] | $13 | [1] |
Amortization of Net Actuarial Loss - From Other Comprehensive Income | 151 | [2] | 12 | [2] |
Electric operation and maintenance expenses | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Amortization of Prior-Service Cost - From Other Comprehensive Income | 4 | 5 | ||
Amortization of Net Actuarial Loss - From Other Comprehensive Income | 78 | 33 | ||
Other nonelectric expenses | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Amortization of Prior-Service Cost - From Other Comprehensive Income | 6 | 8 | ||
Amortization of Net Actuarial Loss - From Other Comprehensive Income | $73 | ($21) | ||
[1] | Amortization of Prior Service Costs from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expensesb $ 4 $ 5 Other Nonelectric Expenses 6 8 | |||
[2] | Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to: Electric Operation and Maintenance Expenses $ 78 $ 33 Other Nonelectric Expenses 73 (21 ) |
Pension_Plan_and_Other_Postret4
Pension Plan and Other Postretirement Benefits (Detail Textuals) (Pension Plan, USD $) | 1 Months Ended | |
Jan. 31, 2015 | Jan. 31, 2014 | |
Pension Plan | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discretionary plan contributions | $10,000,000 | $20,000,000 |
Fair_Value_of_Financial_Instru2
Fair Value of Financial Instruments - Summary of fair value of financial instruments (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Carrying Amount | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Cash and Cash Equivalents | $157 | |
Short-Term Debt | -48,652 | -10,854 |
Long-Term Debt including Current Maturities | -498,641 | -498,690 |
Fair Value | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Cash and Cash Equivalents | 157 | |
Short-Term Debt | -48,652 | -10,854 |
Long-Term Debt including Current Maturities | ($571,801) | ($600,828) |
Fair_Value_of_Financial_Instru3
Fair Value of Financial Instruments (Detail Textuals) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2015 | Dec. 31, 2014 | |
Otter Tail Corporation Credit Agreement | ||
Fair Value Of Financial Instruments [Line Items] | ||
Description of variable rate basis | LIBOR | |
Basis spread on variable rate | 1.75% | |
OTP Credit Agreement | ||
Fair Value Of Financial Instruments [Line Items] | ||
Description of variable rate basis | LIBOR | |
Basis spread on variable rate | 1.25% |
Income_Tax_Expense_Continuing_2
Income Tax Expense - Continuing operations effective income tax rate (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Income Tax Disclosure [Abstract] | ||
Income Before Income Taxes - Continuing Operations | $17,854 | $30,341 |
Tax Computed at Company's Net Composite Federal and State Statutory Rate (39%) | 6,963 | 11,833 |
Increases (Decreases) in Tax from: | ||
Federal Production Tax Credits | 2,054 | 2,252 |
Section 199 Domestic Production Activities Deduction | -362 | -358 |
North Dakota Wind Tax Credit Amortization - Net of Federal Taxes | -212 | -212 |
Employee Stock Ownership Plan Dividend Deduction | -172 | -189 |
AFUDC Equity | -100 | -133 |
Corporate Owned Life Insurance | -80 | -112 |
Other Items - Net | 90 | -15 |
Income Tax Expense - Continuing Operations | $4,073 | $8,562 |
Effective Income Tax Rate - Continuing Operations | 22.80% | 28.20% |
Income_Tax_Expense_Continuing_3
Income Tax Expense - Continuing operations effective income tax rate (Parentheticals) (Details) | 3 Months Ended | |
Mar. 31, 2015 | Mar. 31, 2014 | |
Income Tax Disclosure [Abstract] | ||
Composite Federal and State Statutory Rate | 39.00% | 39.00% |
Income_Tax_Expense_Continuing_4
Income Tax Expense - Continuing Operations - Summary of Activity Related to Unrecognized Tax benefit (Details 1) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Income Tax Disclosure [Abstract] | ||
Balance on January 1 | $222 | $4,239 |
Increases Related to Tax Positions for Prior Years | 137 | |
Increases Related to Tax Positions for Current Year | 44 | |
Uncertain Positions Resolved During Year | ||
Balance on March 31 | $266 | $4,376 |
Discontinued_Operations_Result
Discontinued Operations - Results of discontinued operations (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Net Loss from Operations | ($3,072) | ($349) |
Income Tax Expense on Disposition | 4,816 | |
Net Gain on Disposition | 7,226 | |
Net Income (Loss) | 4,154 | -349 |
Disposal groups held for sale or disposed of by sale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Operating Revenues | 18,724 | 25,506 |
Operating Expenses | 22,141 | 26,368 |
Goodwill Impairment Charge | 1,000 | |
Operating Loss | -4,417 | -862 |
Other (Deductions) Income | -31 | 288 |
Income Tax Benefit | -1,376 | -225 |
Net Loss from Operations | -3,072 | -349 |
Gain on Disposition Before Taxes | 12,042 | |
Income Tax Expense on Disposition | 4,816 | |
Net Gain on Disposition | 7,226 | |
Net Income (Loss) | $4,154 | ($349) |
Discontinued_Operations_Major_
Discontinued Operations - Major components of assets and liabilities of discontinued operations (Details 1) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Assets of Discontinued Operations | $33,171 | $48,657 |
Liabilities of Discontinued Operations | 20,732 | 27,559 |
Disposal groups held for sale or disposed of by sale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Current Assets | 26,928 | 35,174 |
Goodwill and Intangibles | 1,814 | 2,814 |
Net Plant | 4,429 | 10,669 |
Assets of Discontinued Operations | 33,171 | 48,657 |
Current Liabilities | 15,616 | 22,864 |
Deferred Income Taxes | 5,116 | 4,695 |
Liabilities of Discontinued Operations | $20,732 | $27,559 |
Discontinued_Operations_Summar
Discontinued Operations - Summary of costs incurred and billings and estimated earnings recognized on uncompleted contracts (Details 2) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Costs Incurred on Uncompleted Contracts | $339,594 | $402,332 |
Less Billings to Date | -354,256 | -411,909 |
Plus Estimated Earnings Recognized | 14,458 | 15,154 |
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | ($204) | $5,577 |
Discontinued_Operations_Costs_
Discontinued Operations - Costs and estimated earnings in excess of billings that are included in consolidated balance sheets (Details 3) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Costs and Estimated Earnings in Excess of Billings on Uncompleted Contracts | $3,216 | $8,133 |
Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | -3,420 | -2,556 |
Net Billings in Excess of Costs and Estimated Earnings on Uncompleted Contracts | ($204) | $5,577 |
Discontinued_Operations_Warran
Discontinued Operations - Warranty Reserves (Details 4) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Discontinued Operations and Disposal Groups [Abstract] | ||
Warranty Reserve Balance, January 1 | $2,527 | $3,087 |
Additional Provision for Warranties Made During the Year | ||
Settlements Made During the Year | -6 | |
Decrease in Warranty Estimates for Prior Years | -100 | |
Warranty Reserve Balance, March 31 | $2,521 | $2,987 |
Discontinued_Operations_Accoun
Discontinued Operations - Accounts receivable retained by customers pending project completion (Details 5) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Thousands, unless otherwise specified | ||
Discontinued Operations and Disposal Groups [Abstract] | ||
Accounts Receivable Retained by Customers | $4,018 | $6,759 |
Discontinued_Operations_Detail
Discontinued Operations (Detail Textuals) (USD $) | 3 Months Ended | 1 Months Ended | 3 Months Ended | |
Mar. 31, 2015 | Feb. 28, 2015 | Dec. 31, 2014 | Apr. 30, 2015 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of discontinued operations | $21,343,000 | |||
Net Gain on Disposition | 7,226,000 | |||
AEV, Inc. | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of discontinued operations | 22,300,000 | |||
Amount of working capital | 900,000 | |||
Net Gain on Disposition | 7,200,000 | |||
Foley | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Asset Impairment Charges | 1,000,000 | 5,600,000 | ||
Cost estimates pretax charges | 2,300,000 | |||
Foley | Subsequent event | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from sale of Aevenia before working capital and other adjustments | $12,000,000 | |||
Consideration for sale of business, description | The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. |
Subsequent_Events_Detail_Textu
Subsequent Events (Detail Textuals) (Subsequent event, Foley, USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Apr. 30, 2015 |
Subsequent event | Foley | |
Subsequent Event [Line Items] | |
Proceeds from sale of Aevenia before working capital and other adjustments | $12 |
Consideration for sale of business, description | The sale of Foley in exchange for $12.0 million in cash plus adjustments for working capital and other related items to be determined within 120 days of closing. |