Document and Entity Information
Document and Entity Information Document - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | BLACK HILLS POWER INC | ||
Entity Central Index Key | 12,400 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year End Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock Share Outstanding | 23,416,396 | ||
Entity Well-known seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Public Float | $ 0 |
Statements of Income
Statements of Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Revenue | $ 288,433 | $ 267,632 | $ 277,864 |
Operating expenses: | |||
Fuel and purchased power | 87,638 | 75,026 | 83,339 |
Operations and maintenance | 74,064 | 66,384 | 68,088 |
Depreciation and amortization | 35,862 | 34,030 | 32,552 |
Taxes - property | 7,043 | 6,612 | 5,971 |
Total operating expenses | 204,607 | 182,052 | 189,950 |
Operating income | 83,826 | 85,580 | 87,914 |
Other income (expense): | |||
Interest expense | (22,421) | (22,908) | (22,337) |
AFUDC - borrowed | 1,137 | 1,140 | 506 |
Interest income | 904 | 1,576 | 657 |
AFUDC - equity | 2,165 | 2,165 | 918 |
Other expense | (300) | (185) | (117) |
Other income | 115 | 298 | 233 |
Total other income (expense) | (18,400) | (17,914) | (20,140) |
Income before income taxes | 65,426 | 67,666 | 67,774 |
Income tax expense | (14,128) | (22,528) | (22,600) |
Net income | $ 51,298 | $ 45,138 | $ 45,174 |
Statements of Comprehensive Inc
Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net income | $ 51,298 | $ 45,138 | $ 45,174 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax | (94) | (50) | 68 |
Other comprehensive income (loss): | |||
Other comprehensive income (loss) | 4 | 45 | 512 |
Comprehensive income | 51,302 | 45,183 | 45,686 |
Accumulated Defined Benefit Plans Adjustment | |||
Other comprehensive income (loss): | |||
Other comprehensive income (loss) | (38) | 3 | |
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment | |||
Statement of Comprehensive Income [Abstract] | |||
Net income | 56 | 53 | |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, after Tax | 56 | 53 | 61 |
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | |||
Statement of Comprehensive Income [Abstract] | |||
Net income | 42 | 42 | |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ 42 | $ 42 | $ 383 |
Statements of Comprehensive In4
Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Benefit plan liability adjustments - net gain (loss), Tax | $ 50 | $ 27 | $ (36) |
Reclassification adjustment of benefit plan liability - net gain (loss) tax | (30) | (29) | (33) |
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax | $ (22) | $ (22) | $ 319 |
Balance Sheets
Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 16 | $ 234 |
Receivables - customers, net | 29,050 | 30,614 |
Receivables - affiliates | 5,664 | 9,526 |
Other receivables, net | 196 | 351 |
Money pool notes receivable | 0 | 28,409 |
Materials, supplies and fuel | 23,443 | 22,389 |
Regulatory assets, current | 18,993 | 18,119 |
Other current assets | 4,528 | 3,876 |
Total current assets | 81,890 | 113,518 |
Investments | 4,926 | 4,841 |
Property, plant and equipment | 1,311,819 | 1,236,387 |
Less accumulated depreciation and amortization | (358,946) | (338,828) |
Total property, plant and equipment, net | 952,873 | 897,559 |
Other assets: | ||
Regulatory assets, non-current | 59,710 | 74,015 |
Other, non-current assets | 3,747 | 3,816 |
Assets, Noncurrent, Other than Noncurrent Investments and Property, Plant and Equipment | 63,457 | 77,831 |
TOTAL ASSETS | 1,103,146 | 1,093,749 |
Current liabilities: | ||
Accounts payable | 14,766 | 14,158 |
Accounts payable - affiliates | 25,653 | 31,799 |
Money pool note payable | 13,397 | 0 |
Accrued liabilities | 38,205 | 37,436 |
Regulatory liabilities, current | 842 | 84 |
Total current liabilities | 92,863 | 83,477 |
Long-term debt | 339,895 | 339,756 |
Deferred credits and other liabilities: | ||
Deferred income tax liabilities, net | 110,618 | 211,443 |
Regulatory liabilities, non-current | 148,013 | 53,866 |
Benefit plan liabilities | 16,285 | 19,544 |
Other, non-current liabilities | 1,240 | 1,001 |
Total deferred credits and other liabilities | 276,156 | 285,854 |
Commitments and contingencies (Notes 4, 8, 9 and 11) | ||
Stockholder’s equity: | ||
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued | 23,416 | 23,416 |
Additional paid-in capital | 39,575 | 39,575 |
Retained earnings | 332,499 | 322,933 |
Accumulated other comprehensive loss | (1,258) | (1,262) |
Total stockholder’s equity | 394,232 | 384,662 |
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY | $ 1,103,146 | $ 1,093,749 |
Balance Sheets (Parenthetical)
Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common Stock, Par Value Per Share (usd per share) | $ 1 | $ 1 |
Common Stock, Shares Authorized | 50,000,000 | 50,000,000 |
Common Stock, Shares, Issued | 23,416,396 | 23,416,396 |
Statements of Cash Flows
Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities: | |||
Net income | $ 51,298 | $ 45,138 | $ 45,174 |
Adjustments to reconcile net income to net cash provided by operating activities - | |||
Depreciation and amortization | 35,862 | 34,030 | 32,552 |
Deferred income taxes | 1,004 | 20,690 | 7,690 |
AFUDC - equity | (2,165) | (2,165) | (918) |
Employee benefits | 817 | 1,770 | 2,403 |
Other adjustments | 2,429 | 391 | 232 |
Change in operating assets and liabilities - | |||
Accounts receivable and other current assets | 3,287 | (3,963) | (3,223) |
Accounts payable and other current liabilities | (7,254) | 6,175 | 20,455 |
Regulatory assets | 978 | (4,023) | (3,839) |
Regulatory liabilities | 0 | 0 | (2,479) |
Contributions to defined benefit pension plan | (4,000) | (820) | 0 |
Other operating activities | (1,853) | (8,339) | (5,680) |
Net cash provided by operating activities | 80,403 | 88,884 | 92,367 |
Investing activities: | |||
Property, plant and equipment additions | (79,566) | (84,750) | (56,795) |
Notes receivable from affiliate companies, net | 0 | (4,095) | (36,687) |
Other investing activities | (861) | (102) | (128) |
Net cash (used in) investing activities | (80,427) | (88,947) | (93,610) |
Financing activities: | |||
Notes payable from affiliate companies, net | (194) | 0 | 0 |
Other financing activities | 0 | 0 | (2) |
Net cash provided by (used in) financing activities | (194) | 0 | (2) |
Net change in cash and cash equivalents | (218) | (63) | (1,245) |
Cash and cash equivalents beginning of year | 234 | 297 | 1,542 |
Cash and cash equivalents end of year | $ 16 | $ 234 | $ 297 |
Statements of Common Stockholde
Statements of Common Stockholder's Equity - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility HoldingsRetained Earnings |
Common Stock, Shares, Issued - Beginning Balance at Dec. 31, 2014 | 23,416,000 | |||||
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||||||
Stock Issued During Period, Shares, New Issues | 0 | |||||
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2015 | 23,416,000 | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2014 | $ 23,416 | $ 39,575 | $ 313,622 | $ (1,819) | ||
Stockholders' Equity Attributable to Parent [Abstract] | ||||||
Stock Issued During Period, Value, New Issues | 0 | 0 | ||||
Net income | $ 45,174 | 45,174 | ||||
Non-cash Dividend to Parent Company | (28,501) | |||||
Adjustment for Transfer of Utility Money Pool | $ 0 | |||||
Other Comprehensive Income (Loss), Net of Tax | 512 | 512 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2015 | $ 391,979 | $ 23,416 | 39,575 | 330,295 | (1,307) | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||||||
Stock Issued During Period, Shares, New Issues | 0 | |||||
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2016 | 23,416,396 | 23,416,000 | ||||
Stockholders' Equity Attributable to Parent [Abstract] | ||||||
Stock Issued During Period, Value, New Issues | $ 0 | 0 | ||||
Net income | $ 45,138 | 45,138 | ||||
Non-cash Dividend to Parent Company | (52,500) | |||||
Adjustment for Transfer of Utility Money Pool | 0 | |||||
Other Comprehensive Income (Loss), Net of Tax | 45 | 45 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2016 | $ 384,662 | $ 23,416 | 39,575 | 322,933 | (1,262) | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||||||
Stock Issued During Period, Shares, New Issues | 0 | |||||
Common Stock, Shares, Issued - Ending Balance at Dec. 31, 2017 | 23,416,396 | 23,416,000 | ||||
Stockholders' Equity Attributable to Parent [Abstract] | ||||||
Stock Issued During Period, Value, New Issues | $ 0 | 0 | ||||
Net income | $ 51,298 | 51,298 | ||||
Non-cash Dividend to Parent Company | (42,000) | |||||
Adjustment for Transfer of Utility Money Pool | $ 268 | |||||
Other Comprehensive Income (Loss), Net of Tax | 4 | 4 | ||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017 | $ 394,232 | $ 23,416 | $ 39,575 | $ 332,499 | $ (1,258) |
Business Description and Summar
Business Description and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business Description and Significant Accounting Policies | BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Power, Inc., doing business as South Dakota Electric (the Company, “we,” “us” or “our”) is a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange. Basis of Presentation The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3 ) and are prepared in accordance with GAAP. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Regulatory Accounting Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. We had the following regulatory assets and liabilities as of December 31 (in thousands): Maximum Amortization (in years) 2017 2016 Regulatory assets Unamortized loss on reacquired debt (a) 7 $ 1,534 $ 1,815 Deferred taxes on AFUDC (b) 45 5,095 9,367 Employee benefit plans (c) 12 19,465 20,100 Deferred energy and fuel cost adjustments - current (a) 1 14,066 18,119 Deferred gas cost adjustments (a) 1 5,536 4,897 Deferred taxes on flow through accounting (a) 54 7,579 12,545 Decommissioning costs, net of amortization (d) 6 10,252 12,456 Vegetation management, net of amortization (d) 6 12,669 12,109 Other regulatory assets (a) (d) 6 2,507 726 $ 78,703 $ 92,134 Regulatory liabilities Cost of removal for utility plant (a) 61 $ 44,056 $ 41,541 Employee benefit plans and related deferred taxes (c) 12 6,808 12,304 Excess deferred income taxes (c) (e) 40 97,101 — Other regulatory liabilities (c) 13 890 105 $ 148,855 $ 53,950 ____________________ (a) Recovery of costs but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million , vegetation management costs of approximately $14 million , and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years , effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million . (e) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. Regulatory assets represent items we expect to recover from customers through probable future increases in rates. Unamortized Loss on Reacquired Debt - The early redemption premium on reacquired debt is being amortized over the remaining term of the original bonds. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in accumulated other comprehensive income. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation-defined benefit plans to record the full pension and post-retirement benefit obligations. Such amounts have been grossed-up to reflect the revenue requirement associated with a rate regulated environment. Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. We file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by the applicable state utility commissions. Deferred Gas Cost Adjustment - We have GCA provisions that allow us to pass the cost of gas on to our customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. We file periodic estimates of future gas costs based on market forecasts with state utility commissions Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - We received approval in 2014 for regulatory treatment on the remaining net book values and decommissioning costs of our decommissioned coal plants. Vegetation Management Costs - We received approval in 2013 for regulatory treatment on vegetation management maintenance costs for our distribution system rights-of-way. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Cost of Removal for Utility Plant - Cost of removal for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal. Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Excess Deferred Income Taxes - The revaluation of our deferred tax assets and liabilities due to the passage of the TCJA is recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received. We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. Following is a summary of accounts receivable as of December 31 (in thousands): 2017 2016 Accounts receivable, trade $ 15,994 $ 16,972 Unbilled revenue 13,280 13,799 Less Allowance for doubtful accounts (224 ) (157 ) Accounts receivable, net $ 29,050 $ 30,614 Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Materials, Supplies and Fuel Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method. Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.1% in 2017 , 2.2% in 2016 and 2.3% in 2015 . Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands): 2017 2016 Accrued employee compensation, benefits and withholdings $ 4,305 $ 4,783 Accrued property taxes 5,930 5,522 Accrued income taxes 17,472 17,069 Customer deposits and prepayments 4,863 2,825 Accrued interest 4,708 4,614 Other (none of which is individually significant) 927 2,623 Total accrued liabilities $ 38,205 $ 37,436 Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception. Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur. From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes. For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2017, we have no outstanding interest rate swap agreements. Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging. Fair Value Measurements Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Additional information is included in Note 5 . Income Taxes We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21% . The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets. See Note 6 for additional information. Recently Issued Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. We will capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017. We have implemented this standard effective January 1, 2018 on the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2017 2016 Weighted Weighted Average Average Lives (in years) 2017 Useful Life (in years) 2016 Useful Life (in years) Minimum Maximum Electric plant: Production $ 587,323 46 $ 576,833 46 40 54 Transmission 186,045 49 147,398 48 42 60 Distribution 375,214 46 364,304 46 21 62 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 153,535 32 88,114 23 3 40 Total plant-in-service 1,306,987 1,181,519 Construction work in progress 4,832 54,868 Total electric plant 1,311,819 1,236,387 Less accumulated depreciation and amortization (358,946 ) (338,828 ) Electric plant net of accumulated depreciation and amortization $ 952,873 $ 897,559 __________________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining. |
Jointly Owned Facilities
Jointly Owned Facilities | 12 Months Ended |
Dec. 31, 2017 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Jointly Owned Facilities | JOINTLY OWNED FACILITIES Our financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. • We own a 20% interest in the Wyodak Plant (the “Plant”), a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and is the operator of the Plant. We receive our proportionate share of the Plant’s capacity and are committed to pay our share of its additions, replacements and operating and maintenance expenses. • We own a 35% interest in, and are the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW, including 200 MW West to East and 200 MW from East to West. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses. • We own a 52% interest in the Wygen III power plant. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and a proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. • We own 55 MW of Cheyenne Prairie, a 95 MW gas-fired power generation facility located in Cheyenne, Wyoming. Wyoming Electric owns the remaining 40 MW. We are committed to pay our proportionate share of the additions, replacements and operating and maintenance expenses. As of December 31, 2017 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Interest in jointly-owned facilities Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 114,405 $ 727 $ 58,955 Transmission Tie $ 20,037 $ 242 $ 6,215 Wygen III $ 138,688 $ 406 $ 19,239 Cheyenne Prairie $ 91,631 $ 89 $ 8,746 |
Long term Debt
Long term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt outstanding at December 31 was as follows (in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2017 December 31, 2017 December 31, 2016 First Mortgage Bonds due 2032 August 15, 2032 7.23 % $ 75,000 $ 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13 % 180,000 180,000 First Mortgage Bonds due 2044 October 20, 2044 4.43 % 85,000 85,000 Less unamortized debt discount (90 ) (94 ) Series 94A Debt (a) June 1, 2024 1.83 % 2,855 2,855 Less unamortized deferred financing costs (2,870 ) (3,005 ) Long-term Debt $ 339,895 $ 339,756 ___________________ (a) Variable interest rate at December 31, 2017. Net deferred financing costs of approximately $2.9 million and $3.0 million were recorded on the accompanying Balance Sheets in long-term debt at December 31, 2017 and 2016 , respectively, and are being amortized over the term of the debt. Amortization of deferred financing costs of approximately $0.1 million for the years ended December 31, 2017 , 2016 and 2015 are included in Interest expense on the accompanying Statements of Income. Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. We were in compliance with our debt covenants at December 31, 2017 . Long-term Debt Maturities Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands): 2018 $ — 2019 $ — 2020 $ — 2021 $ — 2022 $ — Thereafter $ 342,855 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Disclosures [Text Block] | FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments at December 31 were as follows (in thousands): 2017 2016 Carrying Value Fair Value Carrying Value Fair Value Cash and cash equivalents (a) $ 16 $ 16 $ 234 $ 234 Long-term debt (b) (c) $ 339,895 $ 446,978 $ 339,756 $ 410,466 _______________ (a) Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy. (b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. (c) Carrying amount of long-term debt is net of deferred financing costs. The following methods and assumptions were used to estimate the fair value of each class of our financial instruments. Cash and Cash Equivalents Included in cash and cash equivalents is cash. Long-Term Debt For additional information on our long-term debt, see Note 4 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21% . The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Company’s financial statements, but reasonable estimates could be determined. However, the provisional amounts may change as the Company finalizes the analysis and computations and such changes could be material to the Company’s future results of operations, cash flows or financial position. Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows (in thousands): 2017 2016 2015 Current $ 13,124 $ 1,838 $ 14,910 Deferred 1,004 20,690 7,690 Total income tax expense $ 14,128 $ 22,528 $ 22,600 The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2017 2016 Deferred tax assets: Employee benefits $ 3,012 $ 5,163 Regulatory liabilities 24,984 9,099 Other 1,678 1,815 Total deferred tax assets 29,674 16,077 Deferred tax liabilities: Accelerated depreciation and other plant related differences (a) (122,002 ) (202,047 ) Regulatory assets (7,008 ) (4,391 ) Employee benefits (2,595 ) (3,075 ) Deferred costs (8,447 ) (16,920 ) Other (240 ) (1,087 ) Total deferred tax liabilities (140,292 ) (227,520 ) Net deferred tax liability $ (110,618 ) $ (211,443 ) (a) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $103 million . Due to the regulatory construct, approximately $97 million of the revaluation was reclassified to a regulatory liability. The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% Amortization of excess deferred and investment tax credits (0.1) (0.4) (0.1) AFUDC Equity (1.0) (0.9) (0.6) Flow through adjustments (a) (1.8) (0.9) (0.9) Tax credits — (0.1) — Tax reform (b) (9.2) — — Other (1.3) 0.6 — 21.6% 33.3% 33.4% _________________________ (a) Flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense. (b) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% , effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands): 2017 2016 Unrecognized tax benefits at January 1 $ 493 $ 2,264 Additions for current year tax positions 13 — Additions for prior year tax positions — 1,194 Reductions for prior year tax positions (204 ) (682 ) Settlements for prior year tax positions — (2,283 ) Unrecognized tax benefits at December 31 $ 302 $ 493 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is not material to the financial results of the Company. It is the Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the years ended December 31, 2017 and 2016 , the interest expense recognized was not material to the financial results of the Company. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations on or before December 31, 2018. We file income tax returns in the United States federal jurisdictions as a member of the BHC consolidated group. At December 31, 2016 , we were no longer in a federal NOL carryforward position. |
Comprehensive Income
Comprehensive Income | 12 Months Ended |
Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Comprehensive Income | COMPREHENSIVE INCOME We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands): Location on the Statements of Income (Loss) Amounts Reclassified from AOCI 2017 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ 64 $ 64 Income tax Income tax benefit (expense) (22 ) (22 ) Total reclassification adjustments related to cash flow hedges, net of tax $ 42 $ 42 Amortization of defined benefit plans: Actuarial gain (loss) Operations and maintenance $ 86 $ 82 Income tax Income tax benefit (expense) (30 ) (29 ) Total reclassification adjustments related to defined benefit plans, net of tax $ 56 $ 53 Derivatives designated as cash flow hedges relate to a treasury lock entered into in August 2002 to hedge $50 million of our First Mortgage Bonds due on August 15, 2032 . The treasury lock cash settled on August 8, 2002 , the bond pricing date, and resulted in a $1.8 million loss. The treasury lock is treated as a cash flow hedge and the resulting loss is carried in Accumulated other comprehensive loss and is being amortized over the life of the related bonds. Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands): Interest Rate Swaps Employee Benefit Plans Total As of December 31, 2016 $ (593 ) $ (669 ) $ (1,262 ) Other comprehensive income (loss) 42 (38 ) 4 As of December 31, 2017 $ (551 ) $ (707 ) $ (1,258 ) Interest Rate Swaps Employee Benefit Plans Total As of December 31, 2015 $ (635 ) $ (672 ) $ (1,307 ) Other comprehensive income (loss) 42 3 45 As of December 31, 2016 $ (593 ) $ (669 ) $ (1,262 ) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plan [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Contribution Plans BHC sponsors a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides either a Company Matching Contribution or a Non-Elective Safe Harbor Contribution for all eligible participants. Certain eligible participants receive a Company Retirement Contribution based on the participant’s age and years of service or a Company Discretionary Contribution, depending upon the pension plan in which the employee participates. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Defined Benefit Pension Plan (Pension Plan) We have a defined benefit pension plan (“Pension Plan”) covering certain eligible employees. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan has been closed to new employees and certain employees who did not meet age and service based criteria. The Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016 , reporting beginning in 2017 no longer represents an undivided interest in the Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2017 , the expected rate of return on pension plan assets is based on the targeted asset allocation range of 37% to 45% equity securities and 55% to 63% fixed-income liability-hedging assets and the expected rate of return from these asset categories. The expected long-term rate of return for investments was 6.25% and 6.75% for the Pension Plan 2017 and 2016 plan years, respectively. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows: 2017 2016 Equity securities 26 % 28 % Real estate 4 5 Fixed income funds 63 57 Cash and cash equivalents 1 2 Hedge funds 6 8 Total 100 % 100 % Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company. Plan Assets We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plans Employees who are participants in our Postretirement Healthcare Plan (“Healthcare Plan”) and who retire on or after attaining minimum age and years of service requirements are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. Pre-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHP retirees is provided through an individual market healthcare exchange. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We have determined that the Healthcare Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. Plan Assets We fund our Healthcare Plans on a cash basis as benefits are paid. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands): 2017 2016 Defined Benefit Plans Defined Benefit Pension Plan $ 4,000 $ 820 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 348 $ 420 Supplemental Non-qualified Defined Benefit Plan $ 246 $ 221 Defined Contribution Plans Company Retirement Contribution $ 861 $ 851 Matching Contributions $ 1,306 $ 1,400 While we do not have required contributions, we expect to make approximately $1.8 million in contributions to our Defined Benefit Pension Plan in 2018 . Fair Value Measurements Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 184 $ — $ 184 $ — $ 184 Common Collective Trust - Cash and Cash Equivalents — 314 — 314 — 314 Common Collective Trust - Equity — 15,749 — 15,749 — 15,749 Common Collective Trust - Fixed Income — 37,732 — 37,732 — 37,732 Common Collective Trust - Real Estate — 249 — 249 2,258 2,507 Hedge Funds — — — — 3,398 3,398 Total investments measured at fair value $ — $ 54,228 $ — $ 54,228 $ 5,656 $ 59,884 Pension Plan December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 196 $ — $ 196 $ — $ 196 Common Collective Trust - Cash and Cash Equivalents — 784 — 784 — 784 Common Collective Trust - Equity — 14,927 — 14,927 — 14,927 Common Collective Trust - Fixed Income — 31,003 — 31,003 — 31,003 Common Collective Trust - Real Estate — 347 — 347 2,300 2,647 Hedge Funds — — — — 4,331 4,331 Total investments measured at fair value $ — $ 47,257 $ — $ 47,257 $ 6,631 $ 53,888 ________________________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. AXA Equitable General Fixed Income Fund : This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2. Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. Common Collective Trust-Real Estate Fund : This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Common Collective Trust-Real Estate Fund : This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands): Benefit Obligations As of December 31, Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Projected benefit obligation at beginning of year $ 64,973 $ 65,959 $ 3,404 $ 3,426 $ 5,843 $ 6,208 Service cost 545 606 — — 206 204 Interest cost 2,341 2,499 116 122 176 187 Actuarial loss (gain) 4,008 455 144 78 130 (446 ) Benefits paid (3,445 ) (3,215 ) (246 ) (222 ) (348 ) (420 ) Plan participants transfer to affiliate (860 ) (1,331 ) — — (137 ) (31 ) Plan participants’ contributions — — — — 100 141 Projected benefit obligation at end of year $ 67,562 $ 64,973 $ 3,418 $ 3,404 $ 5,970 $ 5,843 Employee Benefit Plan Assets Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Beginning fair value of plan assets $ 53,888 $ 54,723 $ — $ — $ — $ — Investment income (loss) 6,150 2,485 — — — — Benefits paid (3,445 ) (3,215 ) (246 ) (221 ) (348 ) (420 ) Participant contributions — — — — 100 141 Employer contributions 4,000 820 246 221 248 279 Plan participants transfer to affiliate (709 ) (925 ) — — — — Ending fair value of plan assets $ 59,884 $ 53,888 $ — $ — $ — $ — The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Regulatory asset (liability) $ 18,998 $ 18,974 $ — $ — $ (1,758 ) $ (2,087 ) Current liability $ — $ — $ (245 ) $ (247 ) $ (534 ) $ (541 ) Non-current liability $ (7,676 ) $ (11,085 ) $ (3,173 ) $ (3,157 ) $ (5,436 ) $ (5,302 ) Accumulated Benefit Obligation As of December 31 (in thousands) Defined Benefit Pension Plan Supplemental Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Accumulated benefit obligation (a) $ 64,782 $ 61,585 $ 3,418 $ 3,404 $ 5,970 $ 5,843 ____________________ (a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 545 $ 606 $ 797 $ — $ — $ — $ 206 $ 204 $ 233 Interest cost 2,341 2,499 2,956 116 122 142 176 187 214 Expected return on assets (3,591 ) (3,632 ) (3,935 ) — — — — — — Amortization of prior service cost (credits) 43 43 43 — — — (336 ) (337 ) (336 ) Recognized net actuarial loss (gain) 1,230 1,995 2,196 87 82 93 — — — Net periodic expense $ 568 $ 1,511 $ 2,057 $ 203 $ 204 $ 235 $ 46 $ 54 $ 111 AOCI For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2017 2016 2017 2016 Net (gain) loss $ — $ — $ 707 $ 669 $ — $ — Total AOCI $ — $ — $ 707 $ 669 $ — $ — The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands): Defined Benefits Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan Net gain (loss) $ 1,341 $ 67 $ — Prior service cost 28 — (218 ) Total net periodic benefit cost expected to be recognized during calendar year 2018 $ 1,369 $ 67 $ (218 ) Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2015 2017 2016 2015 2017 2016 2015 Weighted-average assumptions used to determine benefit obligations: Discount rate 3.71 % 4.27 % 4.63 % 3.62 % 4.12 % 4.29 % 3.60 % 3.84 % 4.03 % Rate of increase in compensation levels 3.43 % 3.47 % 3.57 % N/A N/A N/A N/A N/A N/A Weighted-average assumptions used to determine net periodic benefit cost for plan year: Discount rate (a) 4.27 % 4.63 % 4.25 % 4.12 % 4.29 % 3.98 % 3.84 % 4.03 % 3.70 % Expected long-term rate of return on assets (b) 6.75 % 6.75 % 6.75 % N/A N/A N/A N/A N/A N/A Rate of increase in compensation levels 3.47 % 3.57 % 3.86 % N/A N/A N/A N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs. (b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: 2017 2016 Trend Rate - Medical Pre-65 for next year 7.00 % 6.10 % Pre-65 Ultimate trend rate 4.50 % 4.50 % Trend Year 2027 2024 Post-65 for next year 5.00 % 5.10 % Post-65 Ultimate trend rate 4.50 % 4.50 % Trend Year 2026 2023 We do not pre-fund our supplemental plan or our healthcare plan. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plan (in thousands): Change in Assumed Trend Rate Accumulated Periodic Postretirement Benefit Obligation Service and Interest Costs Increase 1% $ 186 $ 7 Decrease 1% $ (174 ) $ (7 ) Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on this Form 10-K for additional details. The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Defined Benefit Postretirement Healthcare Plan 2018 $ 3,489 $ 245 $ 534 2019 $ 3,628 $ 242 $ 621 2020 $ 3,725 $ 239 $ 633 2021 $ 3,835 $ 333 $ 613 2022 $ 3,964 $ 329 $ 592 2023-2027 $ 20,648 $ 1,417 $ 2,479 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED-PARTY TRANSACTIONS Non-Cash Dividend to Parent We recorded non-cash dividends to our Parent of approximately $42 million and $53 million in 2017 and 2016 respectively, and decreased the utility Money pool note receivable for approximately $42 million and $53 million in 2017 and 2016 , respectively. Receivables and Payables We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands): 2017 2016 Receivable - affiliates $ 5,664 $ 9,526 Accounts payable - affiliates $ 25,653 $ 31,799 Money Pool Notes Receivable and Notes Payable On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million , reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million . We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings under the Agreement bear interest at the weighted average daily cost of our parent company’s external borrowings as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month LIBOR plus 1.0% . The cost of borrowing under the Utility Money Pool was 1.96% at December 31, 2017 . We had the following balances with the Utility Money Pool as of December 31 (in thousands): 2017 2016 Notes receivable (payable) $ (13,397 ) $ 28,409 Interest income relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands): 2017 2016 2015 Interest income $ 272 $ 1,047 $ 1,153 Interest expense allocation from Parent BHC provides daily liquidity and cash management on behalf of all its subsidiaries. For the years ended December 31, 2017 , 2016 and 2015 , we were allocated $1.4 million , $1.9 million , and $2.1 million , respectively, of interest expense from BHC. Other Balances and Transactions We have the following Power Purchase and Transmission Services Agreements with affiliated entities: • An agreement, expiring September 3, 2028 , with Wyoming Electric to acquire 15 MW of the facility output from Happy Jack. Under a separate inter-company agreement expiring on September 3, 2028 , Wyoming Electric has agreed to sell up to 15 MW of the facility output from Happy Jack to us. • An agreement, expiring September 30, 2029 , with Wyoming Electric to acquire 20 MW of the facility output from Silver Sage. Under a separate inter-company agreement expiring on September 30, 2029 , Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to us. • A Generation Dispatch Agreement with Wyoming Electric that requires us to purchase all of Wyoming Electric’s excess energy. Related-party Gas Transportation Service Agreement On October 1, 2014, we entered into a gas transportation service agreement with Wyoming Electric in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation. Related-party Revenue and Purchases We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income: 2017 2016 2015 (in thousands) Revenues: Energy sold to Cheyenne Light $ 2,481 $ 2,440 $ 1,857 Rent from electric properties $ 5,100 $ 5,046 $ 4,772 Fuel and purchased power: Purchases of coal from WRDC $ 15,948 $ 16,227 $ 16,401 Purchase of excess energy from Cheyenne Light $ 601 $ 252 $ 898 Purchase of renewable wind energy from Cheyenne Light - Happy Jack $ 1,924 $ 1,918 $ 1,578 Purchase of renewable wind energy from Cheyenne Light - Silver Sage $ 3,290 $ 3,300 $ 2,739 Gas transportation service agreement: Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation $ 393 $ 399 $ 410 Corporate support: Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings $ 27,869 $ 25,748 $ 26,655 Horizon Point Agreement We have an arrangement a mong South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric. This cost allocation, includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | SUPPLEMENTAL CASH FLOW INFORMATION Years ended December 31, 2017 2016 2015 (in thousands) Non-cash investing and financing activities - Property, plant and equipment acquired with accrued liabilities $ 6,565 $ 5,521 $ 3,870 Non-cash decrease to money pool note receivable $ (42,000 ) $ (52,500 ) $ (28,501 ) Non-cash dividend to Parent company $ 42,000 $ 52,500 $ 28,501 Cash (paid) refunded during the period for - Interest (net of amounts capitalized) $ (21,517 ) $ (21,320 ) $ (21,913 ) Income taxes (paid) refunded $ (12,719 ) $ — $ — |
Commitment and Contingencies
Commitment and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Power Purchase and Transmission Services Agreements We have the following power purchase and transmission services agreements, not including related party agreements, as of December 31, 2017 (see Note 9 for information on related party agreements): • A PPA with PacifiCorp, expiring December 31, 2023 , for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. • A firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023 . The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. • An agreement with Thunder Creek for gas transport capacity, expiring October 31, 2019 . Costs incurred under these agreements were as follows for the years ended December 31 (in thousands): Contract Contract Type 2017 2016 2015 PacifiCorp Electric capacity and energy $ 13,218 $ 12,221 $ 13,990 PacifiCorp Transmission access $ 1,671 $ 1,428 $ 1,213 Thunder Creek Gas transport capacity $ 633 $ 633 $ 633 Future Contractual Obligations The following is a schedule of future minimum payments required under power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands): 2018 $ 13,531 2019 $ 6,839 2020 $ 6,839 2021 $ 6,206 2022 $ 6,206 Thereafter $ 6,206 Long-Term Power Sales Agreements We have the following power sales agreements as of December 31, 2017 : • During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023. • An agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023. • During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. • A PPA with MEAN expiring May 31, 2023 . This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. • Effective January 1, 2017, we have an energy sales agreement with Cargill (assigned to Macquarie on January 3, 2018) expiring December 31, 2021 to supply 50 MW of energy during heavy and light load timing intervals. Environmental Matters We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Solid Waste Disposal Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date. For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the financial statements. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities. |
Quarterly Historical Data (Unau
Quarterly Historical Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Information [Abstract] | |
Quarterly Historical Data (Unaudited) | QUARTERLY HISTORICAL DATA (Unaudited) We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter (in thousands): First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Revenues $ 73,794 $ 66,053 $ 73,938 $ 74,648 Operating income $ 23,376 $ 17,712 $ 23,698 $ 19,040 Net income $ 12,570 $ 9,287 $ 13,826 $ 15,615 2016 Revenues $ 68,642 $ 62,019 $ 66,728 $ 70,243 Operating income $ 20,780 $ 18,936 $ 22,410 $ 23,454 Net income $ 11,186 $ 9,806 $ 12,010 $ 12,136 The fourth quarter of 2017 Net income includes a net tax benefit of $6.0 million from the impact of the TCJA. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
Valuation and Qualifying Accounts [Abstract] | |
Schedule II - Valuation and Qualifying Accounts | SCHEDULE II BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, Description Balance at beginning of year Additions charged to costs and expenses Deductions charged to costs and expenses Balance at end of year (in thousands) Allowance for doubtful accounts: 2017 $ 157 $ 882 $ (815 ) $ 224 2016 $ 207 $ 644 $ (694 ) $ 157 2015 $ 261 $ 602 $ (656 ) $ 207 |
Business Description and Summ22
Business Description and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3 ) and are prepared in accordance with GAAP. |
Use of Estimates and Basis of Presentation | Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. |
Cash Equivalents | Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. |
Regulatory Accounting | Regulatory Accounting Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable consists of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs or payment received. We maintain an allowance for doubtful accounts which reflects our best estimate of uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. |
Revenue Recognition | Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. |
Materials, Supplies, and Fuel | Materials, Supplies and Fuel Materials, supplies and fuel used for construction, operation and maintenance purposes are recorded using the weighted-average cost method. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. |
Property, Plant and Equipment | Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Balance Sheets. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated electric properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. Depreciation provisions for regulated electric property, plant and equipment are computed on a straight-line basis using an annual composite rate of 2.1% in 2017 , 2.2% in 2016 and 2.3% in 2015 . |
Derivatives and Hedging Activities | Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instruments be recognized in earnings unless specific hedge accounting criteria are met and designated accordingly, including the normal purchase and normal sales exception. Changes in the fair value for derivative instruments that do not meet this exception are recognized in the income statement as they occur. From time to time we utilize risk management contracts including interest rate swaps to fix the interest on variable rate debt, or to lock in the Treasury yield component associated with anticipated issuance of senior notes. For swaps that settled in connection with the issuance of senior debt, the effective portion is deferred as a component in AOCI and recognized as interest expense over the life of the senior note. As of December 31, 2017, we have no outstanding interest rate swap agreements. Revenues and expenses on contracts that qualify as derivatives may be elected to be accounted for under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our regulated electric operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exception, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging. |
Fair Value Measurements | Fair Value Measurements Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. |
Income Taxes | Income Taxes We file a federal income tax return with other members of the Parent’s consolidated group. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21% . The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. We use the deferral method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other, non-current liabilities on the accompanying Balance Sheets. |
New Accounting Pronouncements | Recently Issued Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. We will capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC to GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income, which are not expected to be material. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017. We have implemented this standard effective January 1, 2018 on the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. We currently expect to adopt this standard on January 1, 2019 and anticipate electing the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems. |
Business Description and Summ23
Business Description and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities as of December 31 (in thousands): Maximum Amortization (in years) 2017 2016 Regulatory assets Unamortized loss on reacquired debt (a) 7 $ 1,534 $ 1,815 Deferred taxes on AFUDC (b) 45 5,095 9,367 Employee benefit plans (c) 12 19,465 20,100 Deferred energy and fuel cost adjustments - current (a) 1 14,066 18,119 Deferred gas cost adjustments (a) 1 5,536 4,897 Deferred taxes on flow through accounting (a) 54 7,579 12,545 Decommissioning costs, net of amortization (d) 6 10,252 12,456 Vegetation management, net of amortization (d) 6 12,669 12,109 Other regulatory assets (a) (d) 6 2,507 726 $ 78,703 $ 92,134 Regulatory liabilities Cost of removal for utility plant (a) 61 $ 44,056 $ 41,541 Employee benefit plans and related deferred taxes (c) 12 6,808 12,304 Excess deferred income taxes (c) (e) 40 97,101 — Other regulatory liabilities (c) 13 890 105 $ 148,855 $ 53,950 ____________________ (a) Recovery of costs but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million , vegetation management costs of approximately $14 million , and Winter Storm Atlas costs of approximately $2.0 million are being amortized over 6 years , effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million . (e) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. Reg |
Schedule of Accounts, Notes, Loans and Financing Receivable | Following is a summary of accounts receivable as of December 31 (in thousands): 2017 2016 Accounts receivable, trade $ 15,994 $ 16,972 Unbilled revenue 13,280 13,799 Less Allowance for doubtful accounts (224 ) (157 ) Accounts receivable, net $ 29,050 $ 30,614 |
Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities on the accompanying Balance Sheets as of December 31 (in thousands): 2017 2016 Accrued employee compensation, benefits and withholdings $ 4,305 $ 4,783 Accrued property taxes 5,930 5,522 Accrued income taxes 17,472 17,069 Customer deposits and prepayments 4,863 2,825 Accrued interest 4,708 4,614 Other (none of which is individually significant) 927 2,623 Total accrued liabilities $ 38,205 $ 37,436 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2017 2016 Weighted Weighted Average Average Lives (in years) 2017 Useful Life (in years) 2016 Useful Life (in years) Minimum Maximum Electric plant: Production $ 587,323 46 $ 576,833 46 40 54 Transmission 186,045 49 147,398 48 42 60 Distribution 375,214 46 364,304 46 21 62 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 153,535 32 88,114 23 3 40 Total plant-in-service 1,306,987 1,181,519 Construction work in progress 4,832 54,868 Total electric plant 1,311,819 1,236,387 Less accumulated depreciation and amortization (358,946 ) (338,828 ) Electric plant net of accumulated depreciation and amortization $ 952,873 $ 897,559 __________________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining. |
Jointly Owned Facilities (Table
Jointly Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule Of Jointly Owned Facilities | As of December 31, 2017 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Interest in jointly-owned facilities Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 114,405 $ 727 $ 58,955 Transmission Tie $ 20,037 $ 242 $ 6,215 Wygen III $ 138,688 $ 406 $ 19,239 Cheyenne Prairie $ 91,631 $ 89 $ 8,746 |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt outstanding at December 31 was as follows (in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2017 December 31, 2017 December 31, 2016 First Mortgage Bonds due 2032 August 15, 2032 7.23 % $ 75,000 $ 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13 % 180,000 180,000 First Mortgage Bonds due 2044 October 20, 2044 4.43 % 85,000 85,000 Less unamortized debt discount (90 ) (94 ) Series 94A Debt (a) June 1, 2024 1.83 % 2,855 2,855 Less unamortized deferred financing costs (2,870 ) (3,005 ) Long-term Debt $ 339,895 $ 339,756 ___________________ (a) Variable interest rate at December 31, 2017. |
Schedule of Maturities of Long-term Debt | Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts and unamortized deferred financing costs) are as follows (in thousands): 2018 $ — 2019 $ — 2020 $ — 2021 $ — 2022 $ — Thereafter $ 342,855 |
Fair Value of Financial Instr27
Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | The estimated fair values of our financial instruments at December 31 were as follows (in thousands): 2017 2016 Carrying Value Fair Value Carrying Value Fair Value Cash and cash equivalents (a) $ 16 $ 16 $ 234 $ 234 Long-term debt (b) (c) $ 339,895 $ 446,978 $ 339,756 $ 410,466 _______________ (a) Fair value approximates carrying value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy. (b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. (c) Carrying amount of long-term debt is net of deferred financing costs. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | Income tax expense (benefit) from continuing operations for the years ended December 31 was as follows (in thousands): 2017 2016 2015 Current $ 13,124 $ 1,838 $ 14,910 Deferred 1,004 20,690 7,690 Total income tax expense $ 14,128 $ 22,528 $ 22,600 |
Schedule of Deferred Tax Assets and Liabilities | The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2017 2016 Deferred tax assets: Employee benefits $ 3,012 $ 5,163 Regulatory liabilities 24,984 9,099 Other 1,678 1,815 Total deferred tax assets 29,674 16,077 Deferred tax liabilities: Accelerated depreciation and other plant related differences (a) (122,002 ) (202,047 ) Regulatory assets (7,008 ) (4,391 ) Employee benefits (2,595 ) (3,075 ) Deferred costs (8,447 ) (16,920 ) Other (240 ) (1,087 ) Total deferred tax liabilities (140,292 ) (227,520 ) Net deferred tax liability $ (110,618 ) $ (211,443 ) (a) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $103 million . Due to the regulatory construct, approximately $97 million of the revaluation was reclassified to a regulatory liability. |
Schedule of Effective Income Tax Rate Reconciliation | The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2017 2016 2015 Federal statutory rate 35.0% 35.0% 35.0% Amortization of excess deferred and investment tax credits (0.1) (0.4) (0.1) AFUDC Equity (1.0) (0.9) (0.6) Flow through adjustments (a) (1.8) (0.9) (0.9) Tax credits — (0.1) — Tax reform (b) (9.2) — — Other (1.3) 0.6 — 21.6% 33.3% 33.4% _________________________ (a) Flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to tax expense. (b) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% , effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. |
Summary of Deferred Tax Liability Not Recognized | The following table reconciles the total amounts of unrecognized tax benefits, without interest, included in Other deferred credits and other liabilities on the accompanying Balance Sheet (in thousands): 2017 2016 Unrecognized tax benefits at January 1 $ 493 $ 2,264 Additions for current year tax positions 13 — Additions for prior year tax positions — 1,194 Reductions for prior year tax positions (204 ) (682 ) Settlements for prior year tax positions — (2,283 ) Unrecognized tax benefits at December 31 $ 302 $ 493 |
Comprehensive Income (Tables)
Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Reclassification out of Accumulated Other Comprehensive Income | The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands): Location on the Statements of Income (Loss) Amounts Reclassified from AOCI 2017 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ 64 $ 64 Income tax Income tax benefit (expense) (22 ) (22 ) Total reclassification adjustments related to cash flow hedges, net of tax $ 42 $ 42 Amortization of defined benefit plans: Actuarial gain (loss) Operations and maintenance $ 86 $ 82 Income tax Income tax benefit (expense) (30 ) (29 ) Total reclassification adjustments related to defined benefit plans, net of tax $ 56 $ 53 |
Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets were as follows (in thousands): Interest Rate Swaps Employee Benefit Plans Total As of December 31, 2016 $ (593 ) $ (669 ) $ (1,262 ) Other comprehensive income (loss) 42 (38 ) 4 As of December 31, 2017 $ (551 ) $ (707 ) $ (1,258 ) Interest Rate Swaps Employee Benefit Plans Total As of December 31, 2015 $ (635 ) $ (672 ) $ (1,307 ) Other comprehensive income (loss) 42 3 45 As of December 31, 2016 $ (593 ) $ (669 ) $ (1,262 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The percentages of total plan asset by investment category of our Pension Plan assets at December 31 were as follows: 2017 2016 Equity securities 26 % 28 % Real estate 4 5 Fixed income funds 63 57 Cash and cash equivalents 1 2 Hedge funds 6 8 Total 100 % 100 % |
Schedule of Contribution to Employee Plans | Contributions for the years ended December 31 were as follows (in thousands): 2017 2016 Defined Benefit Plans Defined Benefit Pension Plan $ 4,000 $ 820 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 348 $ 420 Supplemental Non-qualified Defined Benefit Plan $ 246 $ 221 Defined Contribution Plans Company Retirement Contribution $ 861 $ 851 Matching Contributions $ 1,306 $ 1,400 |
Schedule of Changes in Projected Benefit Obligations | Benefit Obligations As of December 31, Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Projected benefit obligation at beginning of year $ 64,973 $ 65,959 $ 3,404 $ 3,426 $ 5,843 $ 6,208 Service cost 545 606 — — 206 204 Interest cost 2,341 2,499 116 122 176 187 Actuarial loss (gain) 4,008 455 144 78 130 (446 ) Benefits paid (3,445 ) (3,215 ) (246 ) (222 ) (348 ) (420 ) Plan participants transfer to affiliate (860 ) (1,331 ) — — (137 ) (31 ) Plan participants’ contributions — — — — 100 141 Projected benefit obligation at end of year $ 67,562 $ 64,973 $ 3,418 $ 3,404 $ 5,970 $ 5,843 |
Schedule of Changes in Fair Value of Plan Assets | Employee Benefit Plan Assets Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Beginning fair value of plan assets $ 53,888 $ 54,723 $ — $ — $ — $ — Investment income (loss) 6,150 2,485 — — — — Benefits paid (3,445 ) (3,215 ) (246 ) (221 ) (348 ) (420 ) Participant contributions — — — — 100 141 Employer contributions 4,000 820 246 221 248 279 Plan participants transfer to affiliate (709 ) (925 ) — — — — Ending fair value of plan assets $ 59,884 $ 53,888 $ — $ — $ — $ — |
Schedule of Amounts Recognized in Balance Sheet | The funded status of the plans and amounts recognized in the Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Regulatory asset (liability) $ 18,998 $ 18,974 $ — $ — $ (1,758 ) $ (2,087 ) Current liability $ — $ — $ (245 ) $ (247 ) $ (534 ) $ (541 ) Non-current liability $ (7,676 ) $ (11,085 ) $ (3,173 ) $ (3,157 ) $ (5,436 ) $ (5,302 ) |
Schedule of Accumulated and Projected Benefit Obligations | Accumulated Benefit Obligation As of December 31 (in thousands) Defined Benefit Pension Plan Supplemental Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Accumulated benefit obligation (a) $ 64,782 $ 61,585 $ 3,418 $ 3,404 $ 5,970 $ 5,843 ____________________ (a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. |
Schedule of Net Benefit Costs | Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 545 $ 606 $ 797 $ — $ — $ — $ 206 $ 204 $ 233 Interest cost 2,341 2,499 2,956 116 122 142 176 187 214 Expected return on assets (3,591 ) (3,632 ) (3,935 ) — — — — — — Amortization of prior service cost (credits) 43 43 43 — — — (336 ) (337 ) (336 ) Recognized net actuarial loss (gain) 1,230 1,995 2,196 87 82 93 — — — Net periodic expense $ 568 $ 1,511 $ 2,057 $ 203 $ 204 $ 235 $ 46 $ 54 $ 111 |
Schedule of Net Periodic Benefit Cost Not yet Recognized | For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2017 2016 2017 2016 Net (gain) loss $ — $ — $ 707 $ 669 $ — $ — Total AOCI $ — $ — $ 707 $ 669 $ — $ — |
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year | The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands): Defined Benefits Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan Net gain (loss) $ 1,341 $ 67 $ — Prior service cost 28 — (218 ) Total net periodic benefit cost expected to be recognized during calendar year 2018 $ 1,369 $ 67 $ (218 ) |
Schedule of Assumptions Used | Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2017 2016 2015 2017 2016 2015 2017 2016 2015 Weighted-average assumptions used to determine benefit obligations: Discount rate 3.71 % 4.27 % 4.63 % 3.62 % 4.12 % 4.29 % 3.60 % 3.84 % 4.03 % Rate of increase in compensation levels 3.43 % 3.47 % 3.57 % N/A N/A N/A N/A N/A N/A Weighted-average assumptions used to determine net periodic benefit cost for plan year: Discount rate (a) 4.27 % 4.63 % 4.25 % 4.12 % 4.29 % 3.98 % 3.84 % 4.03 % 3.70 % Expected long-term rate of return on assets (b) 6.75 % 6.75 % 6.75 % N/A N/A N/A N/A N/A N/A Rate of increase in compensation levels 3.47 % 3.57 % 3.86 % N/A N/A N/A N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Corporation’s Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs. (b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost. |
Schedule of Health Care Cost Trend Rates | The healthcare benefit obligation was determined at December 31 as follows: 2017 2016 Trend Rate - Medical Pre-65 for next year 7.00 % 6.10 % Pre-65 Ultimate trend rate 4.50 % 4.50 % Trend Year 2027 2024 Post-65 for next year 5.00 % 5.10 % Post-65 Ultimate trend rate 4.50 % 4.50 % Trend Year 2026 2023 |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plan (in thousands): Change in Assumed Trend Rate Accumulated Periodic Postretirement Benefit Obligation Service and Interest Costs Increase 1% $ 186 $ 7 Decrease 1% $ (174 ) $ (7 ) |
Schedule of Expected Benefit Payments | The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Defined Benefit Postretirement Healthcare Plan 2018 $ 3,489 $ 245 $ 534 2019 $ 3,628 $ 242 $ 621 2020 $ 3,725 $ 239 $ 633 2021 $ 3,835 $ 333 $ 613 2022 $ 3,964 $ 329 $ 592 2023-2027 $ 20,648 $ 1,417 $ 2,479 |
Defined Benefit Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 184 $ — $ 184 $ — $ 184 Common Collective Trust - Cash and Cash Equivalents — 314 — 314 — 314 Common Collective Trust - Equity — 15,749 — 15,749 — 15,749 Common Collective Trust - Fixed Income — 37,732 — 37,732 — 37,732 Common Collective Trust - Real Estate — 249 — 249 2,258 2,507 Hedge Funds — — — — 3,398 3,398 Total investments measured at fair value $ — $ 54,228 $ — $ 54,228 $ 5,656 $ 59,884 Pension Plan December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 196 $ — $ 196 $ — $ 196 Common Collective Trust - Cash and Cash Equivalents — 784 — 784 — 784 Common Collective Trust - Equity — 14,927 — 14,927 — 14,927 Common Collective Trust - Fixed Income — 31,003 — 31,003 — 31,003 Common Collective Trust - Real Estate — 347 — 347 2,300 2,647 Hedge Funds — — — — 4,331 4,331 Total investments measured at fair value $ — $ 47,257 $ — $ 47,257 $ 6,631 $ 53,888 ________________________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Accounts Receivable and Payable | We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. These balances as of December 31 were as follows (in thousands): 2017 2016 Receivable - affiliates $ 5,664 $ 9,526 Accounts payable - affiliates $ 25,653 $ 31,799 |
Schedule of Related Party Notes and Associated Interest Income Expense | We had the following balances with the Utility Money Pool as of December 31 (in thousands): 2017 2016 Notes receivable (payable) $ (13,397 ) $ 28,409 |
Schedule of Related Party Interest Income Expense | Interest income relating to the Utility Money Pool for the years ended December 31, was as follows (in thousands): 2017 2016 2015 Interest income $ 272 $ 1,047 $ 1,153 |
Schedule of Revenues and Purchases from Related Parties | We had the following related-party transactions for the years ended December 31 included in the corresponding captions in the accompanying Statements of Income: 2017 2016 2015 (in thousands) Revenues: Energy sold to Cheyenne Light $ 2,481 $ 2,440 $ 1,857 Rent from electric properties $ 5,100 $ 5,046 $ 4,772 Fuel and purchased power: Purchases of coal from WRDC $ 15,948 $ 16,227 $ 16,401 Purchase of excess energy from Cheyenne Light $ 601 $ 252 $ 898 Purchase of renewable wind energy from Cheyenne Light - Happy Jack $ 1,924 $ 1,918 $ 1,578 Purchase of renewable wind energy from Cheyenne Light - Silver Sage $ 3,290 $ 3,300 $ 2,739 Gas transportation service agreement: Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation $ 393 $ 399 $ 410 Corporate support: Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings $ 27,869 $ 25,748 $ 26,655 |
Supplemental Cash Flow Inform32
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | Years ended December 31, 2017 2016 2015 (in thousands) Non-cash investing and financing activities - Property, plant and equipment acquired with accrued liabilities $ 6,565 $ 5,521 $ 3,870 Non-cash decrease to money pool note receivable $ (42,000 ) $ (52,500 ) $ (28,501 ) Non-cash dividend to Parent company $ 42,000 $ 52,500 $ 28,501 Cash (paid) refunded during the period for - Interest (net of amounts capitalized) $ (21,517 ) $ (21,320 ) $ (21,913 ) Income taxes (paid) refunded $ (12,719 ) $ — $ — |
Commitment and Contingencies (T
Commitment and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Long-term Purchase Commitment | Costs incurred under these agreements were as follows for the years ended December 31 (in thousands): Contract Contract Type 2017 2016 2015 PacifiCorp Electric capacity and energy $ 13,218 $ 12,221 $ 13,990 PacifiCorp Transmission access $ 1,671 $ 1,428 $ 1,213 Thunder Creek Gas transport capacity $ 633 $ 633 $ 633 |
Unrecorded Unconditional Purchase Obligations Disclosure | The following is a schedule of future minimum payments required under power purchase, transmission services, facility and vehicle leases, and gas supply agreements (in thousands): 2018 $ 13,531 2019 $ 6,839 2020 $ 6,839 2021 $ 6,206 2022 $ 6,206 Thereafter $ 6,206 |
Quarterly Historical Data (Un34
Quarterly Historical Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Information [Abstract] | |
Schedule of Quarterly Financial Information | The following table sets forth selected unaudited historical operating results data for each quarter (in thousands): First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Revenues $ 73,794 $ 66,053 $ 73,938 $ 74,648 Operating income $ 23,376 $ 17,712 $ 23,698 $ 19,040 Net income $ 12,570 $ 9,287 $ 13,826 $ 15,615 2016 Revenues $ 68,642 $ 62,019 $ 66,728 $ 70,243 Operating income $ 20,780 $ 18,936 $ 22,410 $ 23,454 Net income $ 11,186 $ 9,806 $ 12,010 $ 12,136 |
Business Description and Summ35
Business Description and Summary of Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | Jul. 01, 2017 | Jun. 30, 2017 | Dec. 31, 2017 | Jun. 16, 2017 | Dec. 31, 2016 |
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets | $ 78,703 | $ 92,134 | |||
Regulatory Liabilities | $ 148,855 | 53,950 | |||
Amortization of Regulatory Asset | $ 2,700 | ||||
Cost of removal for utility plant | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Liabilities, Maximum Recovery Period | 61 years | ||||
Regulatory Liabilities | $ 44,056 | 41,541 | |||
Employee benefit plans | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Liabilities, Maximum Recovery Period | 12 years | ||||
Regulatory Liabilities | $ 6,808 | 12,304 | |||
Deferred Income Tax Charges a | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Liabilities, Maximum Recovery Period | 40 years | ||||
Regulatory Liabilities | $ 97,101 | 0 | |||
Other regulatory liabilities | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Liabilities, Maximum Recovery Period | 13 years | ||||
Regulatory Liabilities | $ 890 | 105 | |||
Unamortized loss on reacquired debt | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 7 years | ||||
Regulatory Assets | $ 1,534 | 1,815 | |||
Allowance for Funds Used During Construction | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 45 years | ||||
Regulatory Assets | $ 5,095 | 9,367 | |||
Employee benefit plans | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 12 years | ||||
Regulatory Assets | $ 19,465 | 20,100 | |||
Deferred energy costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 1 year | ||||
Regulatory Assets | $ 14,066 | 18,119 | |||
Asset Recoverable Gas Costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 1 year | ||||
Regulatory Assets | $ 5,536 | 4,897 | |||
Flow through accounting | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 54 years | ||||
Regulatory Assets | $ 7,579 | 12,545 | |||
Decommissioning costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 10,252 | 12,456 | |||
Decommissioning costs | South Dakota Public Utilities Commission (SDPUC) | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 11,000 | ||||
Decommissioning costs | South Dakota Public Utilities Commission (SDPUC) | Scenario, Previously Reported | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 10 years | ||||
Vegetation Management | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 12,669 | 12,109 | |||
Vegetation Management | South Dakota Public Utilities Commission (SDPUC) | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 14,000 | ||||
Other Regulatory Assets | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 2,507 | $ 726 | |||
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Catastrophe | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 6 years | ||||
Regulatory Assets | $ 2,000 | ||||
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Catastrophe | Scenario, Previously Reported | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets, Maximum Recovery Period | 10 years |
Business Description and Summ36
Business Description and Summary of Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Less Allowance for doubtful accounts | $ (224) | $ (157) |
Accounts receivable, net | 29,050 | 30,614 |
Billed Revenues | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, trade | 15,994 | 16,972 |
Unbilled Revenues | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, trade | $ 13,280 | $ 13,799 |
Business Description and Summ37
Business Description and Summary of Significant Accounting Policies: Property, Plant and Equipment (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Composite Depreciation Rate for Plants in Service | 2.10% | 2.20% | 2.30% |
Business Description and Summ38
Business Description and Summary of Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accrued employee compensation, benefits and withholdings | $ 4,305 | $ 4,783 |
Accrued property taxes | 5,930 | 5,522 |
Accrued income taxes | 17,472 | 17,069 |
Customer deposits and prepayments | 4,863 | 2,825 |
Accrued interest | 4,708 | 4,614 |
Other (none of which is individually significant) | 927 | 2,623 |
Total accrued liabilities | $ 38,205 | $ 37,436 |
Property, Plant and Equipment39
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Total plant-in-service | $ 1,306,987 | $ 1,181,519 |
Construction work in progress | 4,832 | 54,868 |
Total electric plant | 1,311,819 | 1,236,387 |
Less accumulated depreciation and amortization | (358,946) | (338,828) |
Electric plant net of accumulated depreciation and amortization | $ 952,873 | 897,559 |
Remaining amortization period | 13 years | |
Electric Production | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Production | $ 587,323 | $ 576,833 |
Electric Production | Weighted average useful life | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 46 years | 46 years |
Electric Production | Minimum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 40 years | |
Electric Production | Maximum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 54 years | |
Electric Transmission | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Transmission | $ 186,045 | $ 147,398 |
Electric Transmission | Weighted average useful life | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 49 years | 48 years |
Electric Transmission | Minimum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 42 years | |
Electric Transmission | Maximum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 60 years | |
Electric Distribution | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Distribution | $ 375,214 | $ 364,304 |
Electric Distribution | Weighted average useful life | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 46 years | 46 years |
Electric Distribution | Minimum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 21 years | |
Electric Distribution | Maximum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 62 years | |
Plant Acquisition Adjustment | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Plant acquisition adjustment | $ 4,870 | $ 4,870 |
Plant Acquisition Adjustment | Weighted average useful life | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 32 years | 32 years |
Plant Acquisition Adjustment | Minimum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 32 years | |
Plant Acquisition Adjustment | Maximum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 32 years | |
General | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
General | $ 153,535 | $ 88,114 |
General | Weighted average useful life | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 32 years | 23 years |
General | Minimum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 3 years | |
General | Maximum | ||
Public Utilities, Property, Plant and Equipment, Net [Abstract] | ||
Useful Life (in years) | 40 years |
Jointly Owned Facilities (Detai
Jointly Owned Facilities (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($)MW | |
Wyodak Plant | |
Jointly Owned Utility Plant Interests [Line Items] | |
Proportionate Ownership Percentage | 20.00% |
Plant in Service | $ 114,405 |
Construction Work in Progress | 727 |
Accumulated Depreciation | $ 58,955 |
Transmission Tie | |
Jointly Owned Utility Plant Interests [Line Items] | |
Proportionate Ownership Percentage | 35.00% |
Utility Plant, Megawatt Capacity | MW | 400 |
Plant in Service | $ 20,037 |
Construction Work in Progress | 242 |
Accumulated Depreciation | $ 6,215 |
Transmission Tie | West to East Transmission Tie | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | MW | 200 |
Transmission Tie | East to West Transmission Tie | |
Jointly Owned Utility Plant Interests [Line Items] | |
Utility Plant, Megawatt Capacity | MW | 200 |
Wygen I I I Generating Facility | |
Jointly Owned Utility Plant Interests [Line Items] | |
Proportionate Ownership Percentage | 52.00% |
Plant in Service | $ 138,688 |
Construction Work in Progress | 406 |
Accumulated Depreciation | $ 19,239 |
Cheyenne Prairie | |
Jointly Owned Utility Plant Interests [Line Items] | |
Electric Generation Capacity, Megawatts | MW | 95 |
Plant in Service | $ 91,631 |
Construction Work in Progress | 89 |
Accumulated Depreciation | $ 8,746 |
Cheyenne Prairie | Wyoming Electric | |
Jointly Owned Utility Plant Interests [Line Items] | |
Electric Generation Capacity, Megawatts | MW | 40 |
Cheyenne Prairie | South Dakota Electric | |
Jointly Owned Utility Plant Interests [Line Items] | |
Electric Generation Capacity, Megawatts | MW | 55 |
Long-term Debt (Details)
Long-term Debt (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Unamortized Discount | $ (90) | $ (94) |
Less unamortized deferred financing costs | (2,870) | (3,005) |
Long-term Debt | 339,895 | 339,756 |
Deferred Finance Costs, Noncurrent, Net | 2,900 | 3,000 |
Amortization of Financing Costs | $ 100 | |
First Mortgage Bonds Due 2032 | ||
Debt Instrument [Line Items] | ||
Interest Rate, Stated Percentage | 7.23% | |
Long-term Debt, Gross | $ 75,000 | 75,000 |
First Mortgage Bonds Due 2039 | ||
Debt Instrument [Line Items] | ||
Interest Rate, Stated Percentage | 6.125% | |
Long-term Debt, Gross | $ 180,000 | 180,000 |
First Mortgage Bonds Due 2044 | ||
Debt Instrument [Line Items] | ||
Interest Rate, Stated Percentage | 4.43% | |
Long-term Debt, Gross | $ 85,000 | 85,000 |
Bonds Due 2024 | ||
Debt Instrument [Line Items] | ||
Variable Interest, Percentage Rate | 1.83% | |
Long-term Debt, Gross | $ 2,855 | $ 2,855 |
Long-term Debt_ Schedule of Mat
Long-term Debt: Schedule of Maturities of Long-term Debt (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Long-term Debt, Unclassified [Abstract] | |
2,018 | $ 0 |
2,019 | 0 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Thereafter | $ 342,855 |
Fair Value of Financial Instr43
Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||
Cash and cash equivalents, at carrying value | $ 16 | $ 234 | $ 297 | $ 1,542 |
Long-term debt, at carrying value | 339,895 | 339,756 | ||
Carrying Value | ||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||
Cash and cash equivalents, at carrying value | 16 | 234 | ||
Long-term debt, at carrying value | 339,895 | 339,756 | ||
Fair Value | ||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||
Cash and cash equivalents, at fair value | 16 | 234 | ||
Long-term debt, at fair value | $ 446,978 | $ 410,466 |
Income Taxes_ Current and Defer
Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Current | $ 13,124 | $ 1,838 | $ 14,910 |
Deferred | 1,004 | 20,690 | 7,690 |
Total income tax expense | $ 14,128 | $ 22,528 | $ 22,600 |
Income Taxes_ Deferred Income T
Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Components of Deferred Tax Assets [Abstract] | ||
Employee benefits | $ 3,012 | $ 5,163 |
Regulatory liabilities | 24,984 | 9,099 |
Other | 1,678 | 1,815 |
Total deferred tax assets | 29,674 | 16,077 |
Components of Deferred Tax Liabilities [Abstract] | ||
Accelerated depreciation and other plant related differences | (122,002) | (202,047) |
Regulatory assets | (7,008) | (4,391) |
Employee benefits | (2,595) | (3,075) |
Deferred costs | (8,447) | (16,920) |
Other | (240) | (1,087) |
Total deferred tax liabilities | (140,292) | (227,520) |
Net deferred tax liability | (110,618) | $ (211,443) |
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | 103,000 | |
Deferred Income Tax Charges a | ||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Provisional Income Tax Expense (Benefit) | $ 97,000 |
Income Taxes_ Effective Tax Rat
Income Taxes: Effective Tax Rate Differences from Statutory Tax Rates (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
Amortization of excess deferred and investment tax credits, percent | (0.10%) | (0.40%) | (0.10%) |
AFUDC Equity, percent | (1.00%) | (0.90%) | (0.60%) |
Flow through adjustments, percent | (1.80%) | (0.90%) | (0.90%) |
Tax credits, percent | (0.00%) | (0.10%) | (0.00%) |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | (9.20%) | 0.00% | 0.00% |
Other, percent | (1.30%) | 0.60% | 0.00% |
Effective Income Tax Rate | 21.60% | 33.30% | 33.40% |
Income Taxes_ Reconciliation of
Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning of Period | $ 493 | $ 2,264 |
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 13 | 0 |
Additions for prior year tax positions | 0 | 1,194 |
Reductions for prior year tax positions | (204) | (682) |
Settlements for prior year tax positions | 0 | (2,283) |
End of Period | $ 302 | $ 493 |
Comprehensive Income_ Other Com
Comprehensive Income: Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Interest Costs Incurred | $ 22,421 | $ 22,908 | $ 22,337 | ||||||||
Income Tax Expense (Benefit) | 14,128 | 22,528 | 22,600 | ||||||||
Net income | $ 15,615 | $ 13,826 | $ 9,287 | $ 12,570 | $ 12,136 | $ 12,010 | $ 9,806 | $ 11,186 | 51,298 | 45,138 | $ 45,174 |
First Mortgage Bonds Due 2032 | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Derivative, Notional Amount | 50,000 | 50,000 | |||||||||
Realized Loss Included Accumulated Other Comprehensive Income (Loss) | $ 1,800 | 1,800 | |||||||||
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Income Tax Expense (Benefit) | (22) | (22) | |||||||||
Net income | 42 | 42 | |||||||||
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Contract | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Interest Costs Incurred | 64 | 64 | |||||||||
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses | 86 | 82 | |||||||||
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Income Tax Expense (Benefit) | (30) | (29) | |||||||||
Net income | $ 56 | $ 53 |
Comprehensive Income_ Accumulat
Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | $ (1,262) | $ (1,307) | |
Other comprehensive income (loss) | 4 | 45 | $ 512 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (1,258) | (1,262) | (1,307) |
Interest Rate Swaps, Cash Flow Hedges, AOCI | Interest Rate Swaps | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (593) | (635) | |
Other comprehensive income (loss) | 42 | 42 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (551) | (593) | (635) |
Employee Benefit Plans, AOCI | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (669) | (672) | |
Other comprehensive income (loss) | (38) | 3 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | $ (707) | $ (669) | $ (672) |
Employee Benefit Plans_ Narrati
Employee Benefit Plans: Narrative (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Maximum Annual Contribution Per Employee, Percent | 50.00% | ||
Employers Matching Contribution, Annual Vesting Percentage | 20.00% | ||
Defined Contribution Plan, Employee Vesting Period | 5 years | ||
Target Plan Asset Allocations, percent | 100.00% | 100.00% | |
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.25% | 6.75% | |
Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Employers Matching Contribution, Annual Vesting Percentage | 100.00% | ||
Equity Securities | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 26.00% | 28.00% | |
Fixed Income Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 63.00% | 57.00% | |
Defined Benefit Pension Plan | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.75% | 6.75% | 6.75% |
Defined Benefit Pension Plan | Equity Securities | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 37.00% | ||
Defined Benefit Pension Plan | Equity Securities | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 45.00% | ||
Defined Benefit Pension Plan | Fixed Income Funds | Minimum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 55.00% | ||
Defined Benefit Pension Plan | Fixed Income Funds | Maximum | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Target Plan Asset Allocations, percent | 63.00% |
Employee Benefit Plans_ Target
Employee Benefit Plans: Target Plan Assets Allocation (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 100.00% | 100.00% |
Equity Securities | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 26.00% | 28.00% |
Real Estate | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 4.00% | 5.00% |
Fixed Income Funds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 63.00% | 57.00% |
Cash and Cash Equivalents | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 1.00% | 2.00% |
Hedge Funds | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Target Plan Asset Allocations, percent | 6.00% | 8.00% |
Employee Benefit Plans_ Plan Co
Employee Benefit Plans: Plan Contribution (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 1,800 | |
Defined Contribution Plan, Company Retirement | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Contribution Plans, Contributions by Employer | 861 | $ 851 |
Defined Contribution Plan, 401K | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Contribution Plans, Contributions by Employer | 1,306 | 1,400 |
Defined Benefit Pension Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer contributions | 4,000 | 820 |
Non-pension Defined Benefit Postretirement Healthcare Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer contributions | 248 | 279 |
Defined Benefit Plans, Employer Contributions | 348 | 420 |
Supplemental Non-qualified Defined Benefit Retirement Plans | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer contributions | 246 | 221 |
Defined Benefit Plans, Employer Contributions | $ 246 | $ 221 |
Employee Benefit Plans_ Fair Va
Employee Benefit Plans: Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period | 65 days | ||
Defined Benefit Pension Plan | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | $ 59,884 | $ 53,888 | $ 54,723 |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 59,884 | 53,888 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 54,228 | 47,257 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 5,656 | 6,631 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 184 | 196 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 184 | 196 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust, Cash And Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 314 | 784 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 314 | 784 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 15,749 | 14,927 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 15,749 | 14,927 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 37,732 | 31,003 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 37,732 | 31,003 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 2,507 | 2,647 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 249 | 347 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 2,258 | 2,300 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 3,398 | 4,331 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 0 | 0 | |
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets | 3,398 | 4,331 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust, Cash And Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 1 | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 54,228 | 47,257 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 184 | 196 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust, Cash And Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 314 | 784 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 15,749 | 14,927 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 37,732 | 31,003 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 249 | 347 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 2 | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust, Cash And Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | 0 | 0 | |
Fair Value, Measurements, Recurring | Defined Benefit Pension Plan | Fair Value, Level 3 | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Total investments measured at fair value | $ 0 | $ 0 |
Employee Benefit Plans_ Changes
Employee Benefit Plans: Changes in Benefit Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Pension Plan | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | $ 64,973 | $ 65,959 | |
Service cost | 545 | 606 | $ 797 |
Interest cost | 2,341 | 2,499 | 2,956 |
Actuarial loss (gain) | 4,008 | 455 | |
Defined Benefit Plan, Benefits Paid | (3,445) | (3,215) | |
Asset transfer (to) from affiliate | (860) | (1,331) | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 67,562 | 64,973 | 65,959 |
Supplemental Non-qualified Defined Benefit Retirement Plans | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 3,404 | 3,426 | |
Service cost | 0 | 0 | 0 |
Interest cost | 116 | 122 | 142 |
Actuarial loss (gain) | 144 | 78 | |
Defined Benefit Plan, Benefits Paid | (246) | (222) | |
Asset transfer (to) from affiliate | 0 | 0 | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 3,418 | 3,404 | 3,426 |
Non-pension Defined Benefit Postretirement Healthcare Plan | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 5,843 | 6,208 | |
Service cost | 206 | 204 | 233 |
Interest cost | 176 | 187 | 214 |
Actuarial loss (gain) | 130 | (446) | |
Defined Benefit Plan, Benefits Paid | (348) | (420) | |
Asset transfer (to) from affiliate | (137) | (31) | |
Plan participants’ contributions | 100 | 141 | |
Projected benefit obligation at end of year | $ 5,970 | $ 5,843 | $ 6,208 |
Employee Benefit Plans_ Chang55
Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Pension Plan | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning market value of plan assets | $ 53,888 | $ 54,723 |
Investment income (loss) | 6,150 | 2,485 |
Benefits paid | (3,445) | (3,215) |
Participant contributions | 0 | 0 |
Employer contributions | 4,000 | 820 |
Asset transfer to affiliate | (709) | (925) |
Ending fair value of plan assets | 59,884 | 53,888 |
Supplemental Non-qualified Defined Benefit Retirement Plans | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning market value of plan assets | 0 | 0 |
Investment income (loss) | 0 | 0 |
Defined Benefit Plan Benefits Paid From Plan and Company Assets | (246) | (221) |
Participant contributions | 0 | 0 |
Employer contributions | 246 | 221 |
Asset transfer to affiliate | 0 | 0 |
Ending fair value of plan assets | 0 | 0 |
Non-pension Defined Benefit Postretirement Healthcare Plan | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning market value of plan assets | 0 | 0 |
Investment income (loss) | 0 | 0 |
Benefits paid | (348) | (420) |
Participant contributions | 100 | 141 |
Employer contributions | 248 | 279 |
Asset transfer to affiliate | 0 | 0 |
Ending fair value of plan assets | $ 0 | $ 0 |
Employee Benefit Plans_ Amounts
Employee Benefit Plans: Amounts Recognized in the Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-current liability | $ (16,285) | $ (19,544) |
Defined Benefit Pension Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory asset (liability) | 18,998 | 18,974 |
Current liability | 0 | 0 |
Non-current liability | (7,676) | (11,085) |
Supplemental Non-qualified Defined Benefit Retirement Plans | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory asset (liability) | 0 | 0 |
Current liability | (245) | (247) |
Non-current liability | (3,173) | (3,157) |
Non-pension Defined Benefit Postretirement Healthcare Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory asset (liability) | (1,758) | (2,087) |
Current liability | (534) | (541) |
Non-current liability | $ (5,436) | $ (5,302) |
Employee Benefit Plans_ Accumul
Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Pension Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated benefit obligation | $ 64,782 | $ 61,585 |
Supplemental Non-qualified Defined Benefit Retirement Plans | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated benefit obligation | 3,418 | 3,404 |
Non-pension Defined Benefit Postretirement Healthcare Plan | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated benefit obligation | $ 5,970 | $ 5,843 |
Employee Benefit Plans_ Compone
Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 545 | $ 606 | $ 797 |
Interest cost | 2,341 | 2,499 | 2,956 |
Expected return on assets | (3,591) | (3,632) | (3,935) |
Amortization of prior service cost (credits) | 43 | 43 | 43 |
Recognized net actuarial loss (gain) | 1,230 | 1,995 | 2,196 |
Net periodic expense | 568 | 1,511 | 2,057 |
Supplemental Non-qualified Defined Benefit Retirement Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 0 | 0 | 0 |
Interest cost | 116 | 122 | 142 |
Expected return on assets | 0 | 0 | 0 |
Amortization of prior service cost (credits) | 0 | 0 | 0 |
Recognized net actuarial loss (gain) | 87 | 82 | 93 |
Net periodic expense | 203 | 204 | 235 |
Non-pension Defined Benefit Postretirement Healthcare Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 206 | 204 | 233 |
Interest cost | 176 | 187 | 214 |
Expected return on assets | 0 | 0 | 0 |
Amortization of prior service cost (credits) | (336) | (337) | (336) |
Recognized net actuarial loss (gain) | 0 | 0 | 0 |
Net periodic expense | $ 46 | $ 54 | $ 111 |
Employee Benefit Plans_ Accum59
Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Pension Plan | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract] | ||
Net loss | $ 0 | $ 0 |
Total accumulated other comprehensive income (loss) | 0 | 0 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 1,341 | |
Prior service cost | 28 | |
Total net periodic benefit cost expected to be recognized during calendar year 2018 | 1,369 | |
Supplemental Non-qualified Defined Benefit Retirement Plans | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract] | ||
Net loss | 707 | 669 |
Total accumulated other comprehensive income (loss) | 707 | 669 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 67 | |
Prior service cost | 0 | |
Total net periodic benefit cost expected to be recognized during calendar year 2018 | 67 | |
Non-pension Defined Benefit Postretirement Healthcare Plan | ||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax [Abstract] | ||
Net loss | 0 | 0 |
Total accumulated other comprehensive income (loss) | 0 | $ 0 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 0 | |
Prior service cost | (218) | |
Total net periodic benefit cost expected to be recognized during calendar year 2018 | $ (218) |
Employee Benefit Plans_ Defined
Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Expected long-term rate of return on assets | 6.25% | 6.75% | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract] | |||
1% Increase on Service and Interest Costs | $ 7 | ||
1% Increase on Accumulated Periodic Postretirement Benefit Obligation | 186 | ||
1% Decrease on Service and Interest Cost | (7) | ||
1% Decrease on Accumulated Periodic Postretirement Benefit Obligation | $ (174) | ||
Defined Benefit Pension Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 3.71% | 4.27% | 4.63% |
Rate of increase in compensation levels | 3.43% | 3.47% | 3.57% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount rate | 4.27% | 4.63% | 4.25% |
Expected long-term rate of return on assets | 6.75% | 6.75% | 6.75% |
Rate of increase in compensation levels | 3.47% | 3.57% | 3.86% |
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 3.71% | ||
Supplemental Non-qualified Defined Benefit Retirement Plans | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 3.62% | 4.12% | 4.29% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount rate | 4.12% | 4.29% | 3.98% |
Non-pension Defined Benefit Postretirement Healthcare Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 3.60% | 3.84% | 4.03% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount rate | 3.84% | 4.03% | 3.70% |
Healthcare trend rate pre-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 7.00% | 6.10% | |
Ultimate trend rate | 4.50% | 4.50% | |
Year Ultimate Trend Reached | 2,027 | 2,024 | |
Healthcare trend rate post-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 5.00% | 5.10% | |
Ultimate trend rate | 4.50% | 4.50% | |
Year Ultimate Trend Reached | 2,026 | 2,023 |
Employee Benefit Plans_ Project
Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Defined Benefit Pension Plan | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,018 | $ 3,489 |
2,019 | 3,628 |
2,020 | 3,725 |
2,021 | 3,835 |
2,022 | 3,964 |
2023-2027 | 20,648 |
Supplemental Non-qualified Defined Benefit Retirement Plans | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,018 | 245 |
2,019 | 242 |
2,020 | 239 |
2,021 | 333 |
2,022 | 329 |
2023-2027 | 1,417 |
Non-pension Defined Benefit Postretirement Healthcare Plan | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,018 | 534 |
2,019 | 621 |
2,020 | 633 |
2,021 | 613 |
2,022 | 592 |
2023-2027 | $ 2,479 |
Employee Benefit Plans_ Defin62
Employee Benefit Plans: Defined Contribution Plan (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plan [Abstract] | |
Maximum Annual Contribution Per Employee, Percent | 50.00% |
Employers Matching Contribution, Annual Vesting Percentage | 20.00% |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Related Party Transaction [Line Items] | |||
Receivables - affiliates | $ 5,664 | $ 9,526 | |
Accounts payable - affiliates | $ 25,653 | 31,799 | |
Utility Money Pool Interest Rate | 1.96% | ||
Money pool note payable | $ 13,397 | 0 | |
Money pool notes receivable | 0 | 28,409 | |
Utility Money Pool | |||
Related Party Transaction [Line Items] | |||
Net interest income (expense) | 272 | 1,047 | $ 1,153 |
Parent | |||
Related Party Transaction [Line Items] | |||
Non-cash dividend to Parent company | $ 42,000 | 52,500 | 28,501 |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 1.00% | ||
Interest Expense, Related Party | $ 1,400 | 1,900 | 2,100 |
Subsidiary of Common Parent | |||
Related Party Transaction [Line Items] | |||
Transfer from Investments | $ 42,000 | 52,500 | 28,501 |
Subsidiary of Common Parent | Purchase Of Natural Gas, Wyoming Gas | |||
Related Party Transaction [Line Items] | |||
Long-term Purchase Commitment, Period | 40 years | ||
Subsidiary of Common Parent | Purchase Of Natural Gas, Cheyenne Light | |||
Related Party Transaction [Line Items] | |||
Costs and Expenses | $ 393 | 399 | 410 |
Subsidiary of Common Parent | Coal, Purchased | |||
Related Party Transaction [Line Items] | |||
Costs and Expenses | 15,948 | 16,227 | 16,401 |
Subsidiary of Common Parent | Purchase of Excess Energy, Cheyenne Light | |||
Related Party Transaction [Line Items] | |||
Costs and Expenses | $ 601 | 252 | 898 |
Subsidiary of Common Parent | Happy Jack Wind Purchase Power Agreeement | |||
Related Party Transaction [Line Items] | |||
Number of Megawatts Capacity Purchased | MW | 15 | ||
Costs and Expenses | $ 1,924 | 1,918 | 1,578 |
Subsidiary of Common Parent | Silver Sage Wind Power Purchase Agreement | |||
Related Party Transaction [Line Items] | |||
Number of Megawatts Capacity Purchased | MW | 20 | ||
Costs and Expenses | $ 3,290 | 3,300 | 2,739 |
Subsidiary of Common Parent | Allocated Costs From Related Parties | |||
Related Party Transaction [Line Items] | |||
Costs and Expenses | 27,869 | 25,748 | 26,655 |
Subsidiary of Common Parent | Energy sold to Wyoming Electric | |||
Related Party Transaction [Line Items] | |||
Revenue | 2,481 | 2,440 | 1,857 |
Subsidiary of Common Parent | Lease Agreements | |||
Related Party Transaction [Line Items] | |||
Revenue | 5,100 | $ 5,046 | $ 4,772 |
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Cash and Cash Equivalents | Subsidiary of Common Parent | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | 700 | ||
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Money Pool Notes Receivable | Subsidiary of Common Parent | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | 1,000 | ||
Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings | Retained Earnings | Subsidiary of Common Parent | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction, Amounts of Transaction | $ 300 |
Supplemental Cash Flow Inform64
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | |||
Property, plant and equipment acquired with accrued liabilities | $ 6,565 | $ 5,521 | $ 3,870 |
Interest and Income Taxes (Paid) Refunded, Cash Flow Information [Abstract] | |||
Interest (net of amounts capitalized) | (21,517) | (21,320) | (21,913) |
Income taxes (paid) refunded | (12,719) | 0 | 0 |
Subsidiary of Common Parent | |||
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | |||
Non-cash decrease to money pool note receivable | (42,000) | (52,500) | (28,501) |
Parent | |||
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract] | |||
Non-cash dividend to Parent company | $ 42,000 | $ 52,500 | $ 28,501 |
Commitment and Contingencies (D
Commitment and Contingencies (Details) $ in Thousands | Jan. 01, 2017MW | Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Contractual Obligation, Fiscal Year Maturity [Abstract] | ||||
2,018 | $ 13,531 | |||
2,019 | 6,839 | |||
2,020 | 6,839 | |||
2,021 | 6,206 | |||
2,022 | 6,206 | |||
Thereafter | $ 6,206 | |||
M D U, Montana Dakota Utilities | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 25 | |||
City Of Gillette | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 23 | |||
Purchase Power Contract, MEAN, 10 M W | ||||
Sales Capacity Commitments [Abstract] | ||||
Long-term Contract To Sell Electric Power, Date of Contract Expiration | May 31, 2023 | |||
Purchase Power Contract, MEAN, 10 M W | Wygen I I I Generating Facility | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 10 | |||
Purchase Power Contract, MEAN, 10 M W | Neil Simpson I I | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 10 | |||
Maximum | M D U, Montana Dakota Utilities | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 50 | |||
Maximum | Cargill Power Purchase Agreement | ||||
Sales Capacity Commitments [Abstract] | ||||
Number of MW Sold Under Long-Term Contract | MW | 50 | |||
Thunder Creek - Gas Transport Capacity | ||||
Long-term Purchase Commitment [Line Items] | ||||
Gas Gathering, Transportation, Marketing and Processing Costs | $ 633 | $ 633 | $ 633 | |
Osage Plant Ash Impoundment | ||||
Sales Capacity Commitments [Abstract] | ||||
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period | 30 years | |||
Osage Plant, Industrial Rubble Landfill | ||||
Sales Capacity Commitments [Abstract] | ||||
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period | 30 years | |||
PacifiCorp Purchase Power Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2023 | |||
Number of Megawatts Capacity Purchased | MW | 50 | |||
Cost of Purchased Power | $ 13,218 | 12,221 | 13,990 | |
PacifiCorp Transmission | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2023 | |||
Number of Megawatts Capacity Purchased | MW | 50 | |||
Cost of Purchased Power | $ 1,671 | $ 1,428 | $ 1,213 |
Quarterly Financial information
Quarterly Financial information Data (Unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Selected Quarterly Financial Information [Abstract] | |||||||||||
Revenues | $ 74,648 | $ 73,938 | $ 66,053 | $ 73,794 | $ 70,243 | $ 66,728 | $ 62,019 | $ 68,642 | $ 288,433 | $ 267,632 | $ 277,864 |
Operating income | 19,040 | 23,698 | 17,712 | 23,376 | 23,454 | 22,410 | 18,936 | 20,780 | 83,826 | 85,580 | 87,914 |
Net income | 15,615 | $ 13,826 | $ 9,287 | $ 12,570 | $ 12,136 | $ 12,010 | $ 9,806 | $ 11,186 | $ 51,298 | $ 45,138 | $ 45,174 |
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Income Tax Expense (Benefit) | $ 6,000 |
Schedule II - Valuation and Q67
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Allowance for doubtful accounts, balance at beginning of year | $ 157 | $ 207 | $ 261 |
Additions charged to costs and expenses | 882 | 644 | 602 |
Deductions charged to costs and expenses | (815) | (694) | (656) |
Allowance for doubtful accounts, balance at end of year | $ 224 | $ 157 | $ 207 |