Document and Entity Information
Document and Entity Information Document - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 31, 2016 | |
Document Information [Line Items] | ||
Entity Registrant Name | BLACK HILLS CORP /SD/ | |
Entity Central Index Key | 1,130,464 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2016 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 53,147,805 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (Loss) (unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |||
Income Statement [Abstract] | ||||||
Revenue | $ 333,786 | $ 272,105 | $ 1,109,186 | $ 986,346 | ||
Operating expenses: | ||||||
Fuel, purchased power and cost of natural gas sold | 80,194 | 71,627 | 336,539 | 350,778 | ||
Operations and maintenance | 115,103 | 89,830 | 334,706 | 273,374 | ||
Depreciation, depletion and amortization | 48,925 | 37,768 | 140,637 | 116,821 | ||
Taxes - property, production and severance | 12,114 | 10,675 | 36,991 | 33,988 | ||
Impairment of long-lived assets | 12,293 | 61,875 | 52,286 | 178,395 | ||
Other operating expenses | 6,748 | 2,374 | 40,730 | 3,392 | ||
Total operating expenses | 275,377 | 274,149 | 941,889 | 956,748 | ||
Operating income (loss) | 58,409 | (2,044) | 167,297 | 29,598 | ||
Interest charges - | ||||||
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts) | (37,306) | (22,378) | (103,989) | (61,833) | ||
Allowance for funds used during construction - borrowed | 860 | 478 | 2,115 | 843 | ||
Capitalized interest | 282 | 280 | 785 | 1,037 | ||
Interest income | 912 | 414 | 2,513 | 1,163 | ||
Allowance for funds used during construction - equity | 1,211 | 430 | 2,900 | 563 | ||
Other income (expense), net | 160 | 842 | 801 | 1,568 | ||
Total other income (expense), net | (33,881) | (19,934) | (94,875) | (56,659) | ||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 24,528 | (21,978) | 72,422 | (27,061) | ||
Equity in earnings (loss) of unconsolidated subsidiaries | 0 | 0 | 0 | (344) | ||
Equity Method Investment, Other than Temporary Impairment | 0 | 0 | 0 | (5,170) | ||
Income tax benefit (expense) | (6,644) | 12,035 | (11,205) | 14,640 | ||
Net income (loss) | 17,884 | (9,943) | 61,217 | (17,935) | ||
Net income attributable to non-controlling interest | (3,753) | 0 | (6,415) | 0 | ||
Net income (loss) available for common stock | $ 14,131 | $ (9,943) | $ 54,802 | $ (17,935) | ||
Earnings Per Share, Basic [Abstract] | ||||||
Earnings (loss) per share, Basic (usd per share) | $ 0.27 | $ (0.22) | $ 1.06 | $ (0.40) | ||
Earnings Per Share, Diluted [Abstract] | ||||||
Earnings (loss) per share, Diluted (usd per share) | $ 0.26 | $ (0.22) | $ 1.04 | $ (0.40) | ||
Weighted average common shares outstanding: | ||||||
Basic (in shares) | 52,184 | 44,635 | 51,583 | 44,598 | ||
Diluted (in shares) | 53,733 | 44,635 | [1] | 52,893 | 44,598 | [1] |
Dividends declared per share of common stock (usd per share) | $ 0.420 | $ 0.405 | $ 1.260 | $ 1.215 | ||
[1] | Due to our net loss for the three and nine months ended September 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015, respectively. |
Condensed Consolidated Stateme3
Condensed Consolidated Statement of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ 17,884 | $ (9,943) | $ 61,217 | $ (17,935) |
Other comprehensive income (loss), net of tax: | ||||
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(260) and $(1,609) for the three months ended 2016 and 2015 and $10,605 and $(1,482) for the nine months ended 2016 and 2015, respectively) | (551) | 2,773 | (20,617) | 2,644 |
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $566 and $558 for the three months ended 2016 and 2015 and $2,450 and $2,548 for the nine months ended 2016 and 2015, respectively) | (923) | (948) | (4,137) | (3,450) |
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $0 for the three months ended 2016 and 2015 and $0 and $16 for the nine months ended 2016 and 2015, respectively) | 0 | 0 | 0 | (27) |
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $19 for the three months ended 2016 and 2015 and $58 and $58 for the nine months ended 2016 and 2015, respectively) | (36) | (36) | (108) | (108) |
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(171) and $(247) for the three months ended 2016 and 2015 and $(516) and $(742) for the nine months ended 2016 and 2015, respectively) | 323 | 459 | 966 | 1,374 |
Other comprehensive income (loss), net of tax | (1,187) | 2,248 | (23,896) | 433 |
Comprehensive income (loss) | 16,697 | (7,695) | 37,321 | (17,502) |
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest | (3,753) | 0 | (6,415) | 0 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | $ 12,944 | $ (7,695) | $ 30,906 | $ (17,502) |
Condensed Consolidated Stateme4
Condensed Consolidated Statement of Comprehensive Income (Loss) (unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | ||||
Fair value adjustment on derivatives designated as cash flow hedges, (tax) benefit | $ (260) | $ (1,609) | $ 10,605 | $ (1,482) |
Reclassification adjustments of cash flow hedges settled and included in net income, (tax) benefit | 566 | 558 | 2,450 | 2,548 |
Benefit plan liability adjustments net gain, (tax) benefit | 0 | 0 | 0 | 16 |
Reclassification adjustment of benefit plan prior service cost included in net income, (tax) benefit | 19 | 19 | 58 | 58 |
Reclassification adjustment of benefit plan liabilities actuarial gain (loss), (tax) benefit | $ (171) | $ (247) | $ (516) | $ (742) |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Current assets: | |||
Cash and cash equivalents | $ 62,964 | $ 456,535 | $ 38,841 |
Restricted cash and equivalents | 2,140 | 1,697 | 2,462 |
Accounts receivable, net | 154,617 | 147,486 | 115,502 |
Materials, supplies and fuel | 113,475 | 86,943 | 90,349 |
Derivative assets, current | 4,382 | 0 | 0 |
Income tax receivable, net | 0 | 368 | 0 |
Deferred income tax assets, net, current | 0 | 0 | 47,783 |
Regulatory assets, current | 50,561 | 57,359 | 51,962 |
Other current assets | 30,032 | 71,763 | 55,383 |
Total current assets | 418,171 | 822,151 | 402,282 |
Investments | 12,416 | 11,985 | 12,148 |
Property, plant and equipment | 6,306,119 | 4,976,778 | 4,882,420 |
Less: accumulated depreciation and depletion | (1,841,116) | (1,717,684) | (1,617,723) |
Total property, plant and equipment, net | 4,465,003 | 3,259,094 | 3,264,697 |
Other assets: | |||
Goodwill | 1,300,379 | 359,759 | 359,527 |
Intangible assets, net | 8,944 | 3,380 | 3,440 |
Regulatory assets, non-current | 234,240 | 175,125 | 182,337 |
Derivative assets, non-current | 183 | 3,441 | 0 |
Other assets, non-current | 12,800 | 7,382 | 7,501 |
Total other assets, non-current | 1,556,546 | 549,087 | 552,805 |
TOTAL ASSETS | 6,452,136 | 4,642,317 | 4,231,932 |
Current liabilities: | |||
Accounts payable | 141,780 | 105,468 | 91,633 |
Accrued liabilities | 228,522 | 232,061 | 229,889 |
Derivative liabilities, current | 1,941 | 2,835 | 3,312 |
Accrued Income Taxes, net | 10,909 | 0 | 308 |
Regulatory liabilities, current | 16,925 | 4,865 | 5,647 |
Notes payable | 75,000 | 76,800 | 117,900 |
Current maturities of long-term debt | 5,743 | 0 | 0 |
Total current liabilities | 480,820 | 422,029 | 448,689 |
Long-term debt | 3,211,768 | 1,853,682 | 1,553,167 |
Deferred credits and other liabilities: | |||
Deferred income tax liabilities, net, non-current | 533,865 | 450,579 | 494,834 |
Derivative liabilities, non-current | 317 | 156 | 722 |
Regulatory liabilities, non-current | 186,496 | 148,176 | 152,164 |
Benefit plan liabilities | 171,633 | 146,459 | 158,682 |
Other deferred credits and other liabilities | 141,007 | 155,369 | 136,462 |
Total deferred credits and other liabilities | 1,033,318 | 900,739 | 942,864 |
Commitments and contingencies (See Notes 10, 11, 12, 18, 19) | |||
Redeemable noncontrolling interest | 4,206 | 0 | 0 |
Stockholders’ equity: | |||
Common stock $1 par value; 100,000,000 shares authorized; issued 53,131,469; 51,231,861; and 44,891,626 shares, respectively | 53,131 | 51,232 | 44,892 |
Additional paid-in capital | 1,123,527 | 953,044 | 753,856 |
Retained earnings | 462,090 | 472,534 | 504,864 |
Treasury stock, at cost – 22,368; 39,720; and 36,711 shares, respectively | (1,155) | (1,888) | (1,789) |
Accumulated other comprehensive income (loss) | (32,951) | (9,055) | (14,611) |
Stockholders' Equity Attributable to Parent | 1,604,642 | 1,465,867 | 1,287,212 |
Noncontrolling Interest in Variable Interest Entity | 117,382 | 0 | 0 |
Total stockholders’ equity | 1,722,024 | 1,465,867 | 1,287,212 |
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ 6,452,136 | $ 4,642,317 | $ 4,231,932 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (unaudited) (Parentheticals) - $ / shares | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Statement of Financial Position [Abstract] | |||
Common Stock, Par Value (usd per share) | $ 1 | $ 1 | $ 1 |
Common Stock, Shares Issued | 53,131,469 | 51,231,861 | 44,891,626 |
Treasury Stock, Shares | 22,368 | 39,720 | 36,711 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 | 100,000,000 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Operating activities: | ||
Net income (loss) available for common stock | $ 54,802 | $ (17,935) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 140,637 | 116,821 |
Deferred financing cost amortization | 4,002 | 3,074 |
Impairment of long-lived assets | 52,286 | 183,565 |
Derivative fair value adjustments | (7,308) | (8,851) |
Stock compensation | 9,124 | 2,868 |
Deferred income taxes | 38,578 | (20,808) |
Employee benefit plans | 11,830 | 15,175 |
Other adjustments, net | (2,076) | 4,013 |
Changes in certain operating assets and liabilities: | ||
Materials, supplies and fuel | (5,166) | 3,618 |
Accounts receivable, unbilled revenues and other operating assets | 78,869 | 75,966 |
Accounts payable and other operating liabilities | (102,155) | (5,255) |
Regulatory assets - current | 8,453 | 27,768 |
Regulatory liabilities - current | (8,181) | 2,457 |
Contributions to defined benefit pension plans | (14,200) | (10,200) |
Interest rate swap settlement | (28,820) | 0 |
Other operating activities, net | (5,998) | (6,403) |
Net cash provided by (used in) operating activities | 224,677 | 365,873 |
Investing activities: | ||
Property, plant and equipment additions | (334,098) | (349,471) |
Acquisition, net of long term debt assumed | (1,124,238) | 0 |
Other investing activities | (860) | (7,189) |
Net cash provided by (used in) investing activities | (1,459,196) | (356,660) |
Financing activities: | ||
Dividends paid on common stock | (65,247) | (54,450) |
Common stock issued | 107,690 | 2,484 |
Sale of noncontrolling interest | 216,370 | 0 |
Short-term borrowings - issuances | 208,100 | 287,910 |
Short-term borrowings - repayments | (209,900) | (245,010) |
Long-term debt - issuances | 1,767,608 | 300,000 |
Long-term debt - repayments | (1,162,872) | (275,000) |
Payments to Noncontrolling Interests | (4,516) | 0 |
Other financing activities | (16,285) | (7,524) |
Net cash provided by (used in) financing activities | 840,948 | 8,410 |
Net change in cash and cash equivalents | (393,571) | 17,623 |
Cash and Cash Equivalents | ||
Cash and cash equivalents, beginning of period | 456,535 | 21,218 |
Cash and cash equivalents, end of period | $ 62,964 | $ 38,841 |
Management's Statement_
Management's Statement: | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Statement | MANAGEMENT’S STATEMENT The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2015 Annual Report on Form 10-K filed with the SEC. Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. In our oil and gas business, we are divesting non-core assets while retaining those best suited for a cost of service gas program and we have refocused our professional staff on assisting our utilities with the implementation of a cost of service gas program. The following changes have been made to our Condensed Consolidated Statements of Income (Loss) to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three and nine months ended September 30, 2015 , respectively: For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 67,282 $ (67,282 ) $ — $ 205,630 $ (205,630 ) $ — Non-regulated energy operations and maintenance $ 22,548 $ (22,548 ) $ — $ 67,744 $ (67,744 ) $ — Operations and maintenance $ — $ 89,830 $ 89,830 $ — $ 273,374 $ 273,374 This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows. Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015 , Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior period has been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 3 for Revenues, Net Income and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the three and nine months ending September 30, 2015 . This segment reclassification did not impact our consolidated financial position, results of operations or cash flows. Use of Estimates and Basis of Presentation Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2016 , December 31, 2015 , and September 30, 2015 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2016 and September 30, 2015 , and our financial condition as of September 30, 2016 , December 31, 2015 , and September 30, 2015 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Significant Accounting Policies Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition. Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests. Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. Recently Issued and Adopted Accounting Standards 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). T his ASU requires changes in the pres entation 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 are currently assessing the impact that adoption of ASU 2016-15 will have on our consolidated financial position, results of operations and cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting . This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We are currently assessing the impact that adoption of ASU 2016-09 will have on our consolidated financial position, results of operations and 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 for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. 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 ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations and cash flows. 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, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. Entities will 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. As of September 30, 2016, we were actively evaluating all of our sources of revenue to determine the impact that adoption of ASU 2014-09 will have on our financial position, results of operations and cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) . The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . Debt issuance costs related to a recognized debt liability are presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of September 30, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million and $15 million in the Condensed Consolidated Balance Sheets as of December 31, 2015, and September 30, 2015, respectively. Adoption of ASU 2015-03 did not have a material impact on our financial position. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments . This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations and cash flows. |
Acquisition_
Acquisition: | 9 Months Ended |
Sep. 30, 2016 | |
Business Combinations [Abstract] | |
Acquisition | ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock and 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $5.2 million and $36 million , respectively, in the three and nine months ended September 30, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Condensed Consolidating Income Statements. There were $4.3 million and $5.0 million of incremental acquisition costs recorded in the three and nine months ended September 30, 2015, respectively. Our consolidated operating results for the three and nine months ended September 30, 2016 include revenues of $72 million and $217 million , respectively, and net income (loss) of $(3.8) million and $0.8 million , respectively, attributable to SourceGas for the period from February 12 through September 30, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. We are still determining the purchase price allocation for SourceGas. A preliminary purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion , net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million , resulted in a preliminary estimate of goodwill totaling $941 million . This estimate is subject to change and will likely result in an increase or decrease in goodwill, which could be material. We have up to one year from the acquisition date to finalize the purchase price allocation. From the time of acquisition through September 30, 2016, we decreased goodwill by $5.8 million , reflecting the working capital adjustment received of $11 million and changes in valuation estimates for long-term debt, intangible assets, accrued liabilities and deferred taxes. Approximately $251 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities. (in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration Paid, net of working capital adjustment received $ 1,124,238 Preliminary Allocation of Purchase Price: Current Assets $ 111,893 Property, plant & equipment, net 1,058,093 Goodwill 940,620 Deferred charges and other assets, excluding goodwill 133,215 Current liabilities (166,807 ) Long-term debt (764,337 ) Deferred credits and other liabilities (188,439 ) Total preliminary consideration paid, net of working-capital adjustment received $ 1,124,238 Conditions of SourceGas Acquisition Regulatory Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below: The APSC order includes a 12 month base rate moratorium, an annual $0.25 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The CPUC order includes a two -year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three -year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The NPSC order includes a three -year base rate moratorium, a three -year continuation of the Choice Gas program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The WPSC order includes a three -year continuation of the Choice Gas program, as well as various other terms and reporting requirements. All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska, however Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs. Settlement of Gas Supply Contract On April 29, 2016, we settled for $40 million , a former SourceGas contract that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities of the preliminary purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of the net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five -year period. Pro Forma Results We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the three and nine months ended September 30, 2016 and 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Revenue $ 333,786 $ 344,498 $ 1,188,148 $ 1,320,047 Net income (loss) available for common stock $ 17,376 $ (14,189 ) $ 89,973 $ (13,884 ) Earnings (loss) per share, Basic $ 0.33 $ (0.28 ) $ 1.74 $ (0.27 ) Earnings (loss) per share, Diluted $ 0.32 $ (0.28 ) $ 1.70 $ (0.27 ) We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the three and nine months ended September 30, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three and nine months ended September 30, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37% . These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future. Seller’s noncontrolling interest One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction, we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas transaction. If we choose not to exercise this option during a ninety-day period, the seller may exercise the put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying condensed consolidated balance sheets. |
Business Segment Information_
Business Segment Information: | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting Information, Additional Information [Abstract] | |
Business Segment Information | BUSINESS SEGMENT INFORMATION Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended September 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 171,754 $ 2,747 $ 24,181 Gas (f) 141,445 — (2,939 ) Power Generation (e) 1,906 21,431 5,642 Mining 9,042 7,778 3,307 Oil and Gas (a) 9,639 — (8,828 ) Corporate activities (c) — — (7,232 ) Inter-company eliminations — (31,956 ) — Total $ 333,786 $ — $ 14,131 Three Months Ended September 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 176,042 $ 2,548 $ 22,659 Gas (d) 75,155 — 652 Power Generation 2,123 21,128 9,067 Mining 8,890 8,076 3,047 Oil and Gas (a) (b) 9,895 — (39,769 ) Corporate activities (c) — — (5,599 ) Inter-company eliminations — (31,752 ) — Total $ 272,105 $ — $ (9,943 ) Nine Months Ended September 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 493,845 $ 9,413 $ 62,625 Gas (f) 563,879 — 29,975 Power Generation (e) 5,304 63,055 19,907 Mining 20,498 23,651 6,969 Oil and Gas (a) 25,660 — (35,277 ) Corporate activities (c) — — (29,397 ) Inter-company eliminations — (96,119 ) — Total $ 1,109,186 $ — $ 54,802 Nine Months Ended September 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 504,049 $ 8,481 $ 57,844 Gas (d) 416,950 — 27,475 Power Generation 5,782 62,452 24,761 Mining 26,084 23,541 9,106 Oil and Gas (a) (b) 33,481 — (130,079 ) Corporate activities (c) — — (7,042 ) Inter-company eliminations — (94,474 ) — Total $ 986,346 $ — $ (17,935 ) ___________ (a) Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million and $36 million and $113 million , respectively. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) available for common stock for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million . See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $4.0 million and $24 million ; and $2.8 million and $3.0 million respectively, and after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million ; and $1.2 million and $1.8 million respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $6.2 million and $31 million , respectively, and Net loss of $1.0 million and Net income of $0.5 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (e) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.8 million and $6.4 million for the three and nine months ended September 30, 2016 . (f) Gas Utility revenue increased for the three and nine months ended September 30, 2016 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016. Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: September 30, 2016 December 31, 2015 September 30, 2015 Segment: Electric (a) (b) $ 2,824,145 $ 2,720,004 $ 2,706,654 Gas (b) (e) 3,182,852 999,778 967,225 Power Generation (a) 77,570 60,864 78,666 Mining 66,804 76,357 78,000 Oil and Gas (c) 158,970 208,956 280,842 Corporate activities (d) 141,795 576,358 120,545 Total assets $ 6,452,136 $ 4,642,317 $ 4,231,932 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $136 million , respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and September 30, 2015 . (c) As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $52 million for the nine months ended September 30, 2016 , $250 million for the year ended December 31, 2015 , and $178 million for the nine months ended September 30, 2015 . See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016. (e) Includes the assets acquired in the SourceGas acquisition on February 12, 2016. |
Accounts Receivable_
Accounts Receivable: | 9 Months Ended |
Sep. 30, 2016 | |
Receivables [Abstract] | |
Accounts Receivable | ACCOUNTS RECEIVABLE Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts September 30, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 44,747 $ 30,970 $ (580 ) $ 75,137 Gas Utilities 48,057 23,582 (1,923 ) 69,716 Power Generation 1,165 — — 1,165 Mining 3,612 — — 3,612 Oil and Gas 3,341 — (13 ) 3,328 Corporate 1,659 — — 1,659 Total $ 102,581 $ 54,552 $ (2,516 ) $ 154,617 Accounts Unbilled Less Allowance for Accounts December 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,331 32,869 (1,001 ) 62,199 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,025 — — 1,025 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 Accounts Unbilled Less Allowance for Accounts September 30, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,655 $ 33,979 $ (811 ) $ 74,823 Gas Utilities (a) 20,031 11,230 (527 ) 30,734 Power Generation 1,186 — — 1,186 Mining 2,684 — — 2,684 Oil and Gas 4,522 — (13 ) 4,509 Corporate 1,566 — — 1,566 Total $ 71,644 $ 45,209 $ (1,351 ) $ 115,502 ___________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $2.9 million as of December 31, 2015 and September 30, 2015 , respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment. |
Regulatory Accounting_
Regulatory Accounting: | 9 Months Ended |
Sep. 30, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Accounting | REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) September 30, 2016 December 31, 2015 September 30, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 16,525 $ 24,751 $ 25,354 Deferred gas cost adjustments (a)(d) 1 12,172 15,521 9,358 Gas price derivatives (a) 7 14,405 23,583 23,681 AFUDC (b) 45 14,093 12,870 12,580 Employee benefit plans (c) (e) 12 107,578 83,986 95,779 Environmental (a) subject to approval 1,126 1,180 1,209 Asset retirement obligations (a) 44 507 457 675 Loss on reacquired debt (a) 30 15,918 3,133 3,169 Renewable energy standard adjustment (b) 5 1,694 5,068 5,102 Flow through accounting (c) 35 33,136 29,722 28,585 Decommissioning costs (f) 10 17,271 18,310 16,353 Gas supply contract termination 5 28,164 — — Other regulatory assets (a) 15 22,212 13,903 12,454 $ 284,801 $ 232,484 $ 234,299 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 15,033 $ 7,814 $ 9,899 Employee benefit plans (c) (e) 12 65,575 47,218 53,140 Cost of removal (a) 44 114,616 90,045 86,946 Other regulatory liabilities (c) 25 8,197 7,964 7,826 $ 203,421 $ 153,041 $ 157,811 __________ (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) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. (e) Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs. Loss on reacquired debt - The increase from the prior periods is the loss on the early retirement of debt assumed in the SourceGas Acquisition. These costs are being amortized to interest expense over a maximum period of 30 years. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We terminated the contract and settled the liability on April 29, 2016. Cost of Removal - Cost of Removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense. The increase from the prior periods is primarily due to cost of removal recorded with the SourceGas purchase price allocation. |
Materials, Supplies and Fuel_
Materials, Supplies and Fuel: | 9 Months Ended |
Sep. 30, 2016 | |
Inventory, Net [Abstract] | |
Materials, Supplies and Fuel | MATERIALS, SUPPLIES AND FUEL The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Materials and supplies $ 67,257 $ 55,726 $ 53,838 Fuel - Electric Utilities 4,282 5,567 6,139 Natural gas in storage held for distribution 41,936 25,650 30,372 Total materials, supplies and fuel $ 113,475 $ 86,943 $ 90,349 |
Goodwill & Intangible Assets_
Goodwill & Intangible Assets: | 9 Months Ended |
Sep. 30, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets | GOODWILL & INTANGIBLE ASSETS Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 256,850 $ 94,144 $ 8,765 $ 359,759 Acquisition of SourceGas (a) — 940,620 — 940,620 Ending balance at September 30, 2016 $ 256,850 $ 1,034,764 $ 8,765 $ 1,300,379 __________ (a) Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. (b) Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details. Following is a summary of Intangible assets included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Intangible assets, net beginning balance at December 31, 2015 $ 3,380 Additions/amortization, net (a) 5,564 Intangible assets, net, ending balance at September 30, 2016 $ 8,944 __________ (a) Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10 -year estimated useful lives. See Note 2 for more information. |
Asset Retirement Obligations_
Asset Retirement Obligations: | 9 Months Ended |
Sep. 30, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS The following table presents the details of asset retirement obligations which are included on the accompanying Condensed Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b) (c) September 30, 2016 Electric Utilities $ 4,462 $ — $ — $ 143 $ — $ 11 $ 4,616 Gas Utilities 136 — — 478 22,412 6,436 29,462 Mining 18,633 — (15 ) 653 — (5,603 ) 13,668 Oil and Gas 21,504 — (814 ) 1,047 — 57 21,794 Total $ 44,735 $ — $ (829 ) $ 2,321 $ 22,412 $ 901 $ 69,540 __________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. |
Earnings Per Share_
Earnings Per Share: | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | EARNINGS PER SHARE A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Net income (loss) available for common stock $ 14,131 $ (9,943 ) $ 54,802 $ (17,935 ) Weighted average shares - basic 52,184 44,635 51,583 44,598 Dilutive effect of: Equity Units (a) 1,414 — 1,191 — Equity compensation 135 — 119 — Weighted average shares - diluted (b) 53,733 44,635 52,893 44,598 __________ (a) Calculated using the treasury stock method. (b) Due to our net loss for the three and nine months ended September 30, 2015 , potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015 , respectively. The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Equity compensation 2 121 4 114 Anti-dilutive shares 2 121 4 114 |
Notes Payable_
Notes Payable: | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Short-term Debt [Text Block] | NOTES PAYABLE We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 75,000 $ 30,500 $ 76,800 $ 33,399 $ 117,900 $ 30,600 Revolving Credit Facility On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one -year extension options. This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase total commitments of the facility up to $1 billion . Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125% , 1.125% , and 1.125% , respectively, at September 30, 2016 . A 0.175% commitment fee is charged on the unused amount of the Revolving Credit Facility. Debt Financial Covenants On February 12, 2016, in connection with the SourceGas Acquisition discussed in Note 2 , our Revolving Credit Facility and Term Loan credit agreements were amended to permit the assumption of certain indebtedness of SourceGas and to increase the Recourse Leverage Ratio. We also amended and restated SourceGas’s $340 million term loan due June 30, 2017. On February 12, 2016, the maximum Recourse Leverage Ratio increased to 0.75 to 1.00 until March 31, 2017, a period of four fiscal quarters following the SourceGas acquisition; it was previously 0.65 to 1.00 . On August 9, 2016, in conjunction with the amendment and restatement of the Revolving Credit Facility and Term Loan, the Recourse Leverage Ratio was amended and replaced with the Consolidated Indebtedness to Capitalization Ratio. Under the amended and restated Revolving Credit Facility and Term Loan, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 at the end of fiscal quarters ending September 30, 2016 and December 31, 2016 and not to exceed 0.65 to 1.00 at the end of any fiscal quarter thereafter. Except as provided above, our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: As of September 30, 2016 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 68% Less than 70% As of September 30, 2016 , we were in compliance with this covenant. |
Long-Term Debt And Current Matu
Long-Term Debt And Current Maturities Of Long-Term Debt: | 9 Months Ended |
Sep. 30, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt [Text Block] | LONG-TERM DEBT AND CURRENT MATURITIES OF LONG-TERM DEBT Long-term debt was as follows (dollars in thousands): Interest Rate at September 30, 2016 September 30, 2016 December 31, 2015 September 30, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (842 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,685 ) (1,890 ) (1,959 ) Senior unsecured notes due July 15, 2020 5.88% 200,000 200,000 200,000 Senior unsecured notes due January 11, 2019 2.50% 250,000 — — Unamortized discount on Senior unsecured notes due 2019 (205 ) — — Senior unsecured notes due January 15, 2027 3.15% 400,000 — — Unamortized discount on Senior unsecured notes due 2027 (202 ) — — Senior unsecured notes, due September 15, 2046 4.20% 300,000 — — Unamortized discount on Senior unsecured notes due 2046 (1,630 ) — — Corporate term loan due August 9, 2019 (a) 1.46% 400,000 — — Corporate term loan due April 12, 2017 (a) — 300,000 300,000 Corporate term loan due June 7, 2021 2.32% 25,842 — — Total Corporate Debt 2,695,278 1,322,110 1,023,041 Electric Utilities First Mortgage Bonds due October 20, 2044 4.43% 85,000 85,000 85,000 First Mortgage Bonds due October 20, 2044 4.53% 75,000 75,000 75,000 First Mortgage Bonds due August 15, 2032 7.23% 75,000 75,000 75,000 First Mortgage Bonds due November 1, 2039 6.13% 180,000 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (96 ) (99 ) (99 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (b) 0.86% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (b) 0.86% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (b) 1.01% 2,855 2,855 2,855 Total Electric Utilities Debt 544,759 544,756 544,756 Total long-term debt 3,240,037 1,866,866 1,567,797 Less current maturities 5,743 — — Less deferred financing costs (c) 22,526 13,184 14,630 Long-term debt, net of current maturities $ 3,211,768 $ 1,853,682 $ 1,553,167 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) Variable interest rate. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $2.5 million , $1.7 million and $1.9 million as of September 30, 2016 , December 31, 2015 and September 30, 2015 , respectively. Scheduled future maturities of debt, excluding amortization of premiums or discounts are (in thousands): Year Ended: 2016 $ 1,436 2017 $ 5,743 2018 $ 5,743 2019 $ 655,743 2020 $ 205,742 Thereafter $ 2,370,290 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at September 30, 2016 . Current Maturities of Long-Term Debt As of September 30, 2016 , we have the following classified as Current maturities of long-term debt: Loan Interest Rate Current Maturities at September 30, 2016 Corporate Corporate term loan due June 7, 2021 (a) 2.32% 5,743 Current Maturities of Long-Term Debt $ 5,743 _______________ (a) Principal payments of $1.4 million are due quarterly . Debt Transactions On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% ten -year senior notes due January 15, 2027 and $300 million of 4.20% 30 -year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following: • Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition; • Repay the $95 million , 3.98% senior secured notes assumed in the SourceGas Acquisition; • Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition; • Pay down $100 million of the $500 million three -year unsecured term loan discussed below; • Payment of $29 million for the settlement of $400 million notional interest rate swap; and • Remainder was used for general corporate purposes. On August 9, 2016, we entered into a $500 million , three -year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan was used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017 . This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 5, on June 7, 2016, we entered into a 2.32% , $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million , the first of which were paid on June 30, 2016. On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95% , ten -year senior notes due 2026, and $250 million of 2.50% , three -year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note. Assumption of Long-Term Debt At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following: • $325 million , 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017. • $95 million , 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019. • $340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875% . As of September 30, 2016 , the $760 million in long-term debt assumed in the SourceGas Acquisition was repaid. |
Equity_
Equity: | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Stockholders' Equity [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | ( 12 ) EQUITY A summary of the changes in equity is as follows: Nine Months Ended September 30, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 $ — $ 1,465,867 Net income (loss) 54,802 6,402 61,204 Other comprehensive income (loss) (23,896 ) — (23,896 ) Dividends on common stock (65,247 ) — (65,247 ) Share-based compensation 3,822 — 3,822 Issuance of common stock 105,238 — 105,238 Dividend reinvestment and stock purchase plan 2,242 — 2,242 Other stock transactions (24 ) — (24 ) Sale of noncontrolling interest 61,838 115,496 177,334 Distribution to noncontrolling interest — (4,516 ) $ (4,516 ) Balance at September 30, 2016 $ 1,604,642 $ 117,382 $ 1,722,024 Nine Months Ended September 30, 2015 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 $ — $ 1,353,884 Net income (loss) (17,935 ) — (17,935 ) Other comprehensive income (loss) 433 — 433 Dividends on common stock (54,450 ) — (54,450 ) Share-based compensation 2,998 — 2,998 Issuance of common stock — — — Dividend reinvestment and stock purchase plan 2,298 — 2,298 Other stock transactions (16 ) — (16 ) Balance at September 30, 2015 $ 1,287,212 $ — $ 1,287,212 At-the-Market Equity Offering Program On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million . The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended September 30, 2016, we issued 819,442 common shares for $49 million , net of $0.5 million in commissions under the ATM equity offering program. Through September 30, 2016, we have sold and issued an aggregate of 1,750,091 shares of common stock under the ATM equity offering program for $106 million , net of $1.1 million in commissions. Additionally, 38,781 shares for net proceeds of $2.4 million have been sold, but were not settled and are not considered issued and outstanding as of September 30, 2016. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. ASC 810 requires the accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of: September 30, 2016 December 31, 2015 September 30, 2015 (in thousands) Assets Current assets $ 14,191 $ — $ — Property, plant and equipment of variable interest entities, net $ 220,818 $ — $ — Liabilities Current liabilities $ 3,353 $ — $ — |
Risk Management Activities_
Risk Management Activities: | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management Activities | RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2015 Annual Report on Form 10-K. Market Risk Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to: • Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets; and • Interest rate risk associated with our variable-rate debt. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and in Note 14 . Oil and Gas We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows. To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly. The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of: September 30, 2016 December 31, 2015 September 30, 2015 Crude Oil Futures Natural Gas Futures and Swaps Call Options Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 159,000 1,625,000 36,000 198,000 4,392,500 258,000 5,392,500 Maximum terms in months (b) 27 15 15 24 24 27 27 __________ (a) Crude oil futures and call options in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged. Based on September 30, 2016 prices, a $2.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate. Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, fixed to float swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss), or the Condensed Consolidated Statements of Comprehensive Income (Loss). For hedging activities associated with our retail marketing operations, the effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in a net long position as of: September 30, 2016 December 31, 2015 September 30, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 17,740,000 51 20,580,000 60 17,180,000 63 Natural gas options purchased, net (b) 6,540,000 17 2,620,000 3 6,300,000 6 Natural gas basis swaps purchased 13,650,000 51 18,150,000 60 12,980,000 51 Natural gas fixed for float swaps, net (c) 4,749,000 20 — 0 — 0 Natural gas physical commitments, net 15,666,202 13 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of September 30, 2016 is net of 2,306,000 MMBtus of collar options (call purchase and put sale) transactions. (c) 2,640,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased. Financing Activities In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to reduce the interest rate risk associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten -year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten -year life of the $400 million unsecured senior note issued on August 19, 2016. The ineffectiveness portion of $1.0 million , related to the timing of the debt issuance, was recognized in earnings as a component of interest expense. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Interest Rate Swaps (b) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (b) Notional $ 75,000 $ 250,000 $ 75,000 $ 75,000 Weighted average fixed interest rate 4.97 % 2.29 % 4.97 % 4.97 % Maximum terms in years 0.33 1.33 1.00 1.33 Derivative assets, non-current $ — $ 3,441 $ — $ — Derivative liabilities, current $ 654 $ — $ 2,835 $ 3,312 Derivative liabilities, non-current $ — $ — $ 156 $ 722 __________ (a) These swaps were settled in August 2016 in conjunction with the refinancing of acquired SourceGas debt. (b) These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings. Based on September 30, 2016 market interest rates and balances related to our interest rate swaps, a loss of approximately $ 3.4 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. This total includes the amortization of the $28 million loss currently deferred in AOCI. Estimated and actual realized gains or losses will change during future periods as market interest rates change. Cash Flow Hedges The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended September 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (465 ) Interest expense $ 840 Interest expense $ — Commodity derivatives 727 Revenue (2,201 ) Revenue — Commodity derivatives (553 ) Fuel, purchased power and cost of natural gas sold (128 ) Fuel, purchased power and cost of natural gas sold — Total $ (291 ) $ (1,489 ) $ — Three Months Ended September 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (898 ) Interest expense $ 1,603 Interest expense $ — Commodity derivatives 5,280 Revenue (3,109 ) Revenue — Total $ 4,382 $ (1,506 ) $ — Nine Months Ended September 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (31,130 ) Interest expense $ 2,530 Interest expense $ — Commodity derivatives (312 ) Revenue (9,140 ) Revenue — Commodity derivatives 220 Fuel, purchased power and cost of natural gas sold 23 Fuel, purchased power and cost of natural gas sold — Total $ (31,222 ) $ (6,587 ) $ — Nine Months Ended September 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (2,674 ) Interest expense $ 4,709 Interest expense $ — Commodity derivatives 6,800 Revenue (10,707 ) Revenue — Total $ 4,126 $ (5,998 ) $ — |
Fair Value Measurements_
Fair Value Measurements: | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Derivative Financial Instruments The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. 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. For additional information, see Notes 1 , 9 , 10 and 11 to the Consolidated Financial Statements included in our 2015 Annual Report on Form 10-K filed with the SEC. 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 when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Oil and Gas Segment: • The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures, basis swaps and call options. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure. Utilities Segments: • The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Corporate Activities: • The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that takes into account our credit ratings, and the credit rating of our counterparty. Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of September 30, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 2,882 $ — $ — $ 2,882 Commodity derivatives — Utilities — 5,330 — (3,647 ) 1,683 Interest Rate Swaps — — — — — Total $ — $ 8,212 $ — $ (3,647 ) $ 4,565 Liabilities: Commodity derivatives — Oil and Gas $ — $ 705 $ — $ — $ 705 Commodity derivatives — Utilities — 16,130 — (15,231 ) 899 Interest rate swaps — 654 — — 654 Total $ — $ 17,489 $ — $ (15,231 ) $ 2,258 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 10,644 $ — $ (10,644 ) $ — Commodity derivatives —Utilities — 2,293 — (2,293 ) — Interest Rate Swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives — Oil and Gas $ — $ 556 $ — $ (556 ) $ — Commodity derivatives — Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of September 30, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 11,264 $ — $ (11,264 ) $ — Commodity derivatives — Utilities — 3,123 — (3,123 ) — Interest Rate Swaps — — — — — Total $ — $ 14,387 $ — $ (14,387 ) $ — Liabilities: Commodity derivatives — Oil and Gas $ — $ 467 $ — $ (467 ) $ — Commodity derivatives — Utilities — 24,445 — (24,445 ) — Interest rate swaps — 4,034 — — 4,034 Total $ — $ 28,946 $ — $ (24,912 ) $ 4,034 Fair Value Measures by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. Additionally, as of December 31, 2015 , and September 30, 2015 , the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 13 as they are netted in other current assets. The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of September 30, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2,919 $ — Commodity derivatives Derivative assets — non-current 66 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 479 Commodity derivatives Derivative liabilities — non-current — 256 Interest rate swaps Derivative liabilities — current — 654 Interest rate swaps Derivative liabilities — non-current — — Total derivatives designated as hedges $ 2,985 $ 1,389 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,463 $ — Commodity derivatives Derivative assets — non-current 117 — Commodity derivatives Derivative liabilities — current — 808 Commodity derivatives Derivative liabilities — non-current — 61 Total derivatives not designated as hedges $ 1,580 $ 869 As of December 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,981 $ — Commodity derivatives Derivative assets — non-current 663 — Interest rate swaps Derivative assets — non-current 3,441 — Commodity derivatives Derivative liabilities — current — 465 Commodity derivatives Derivative liabilities — non-current — 91 Interest rate swaps Derivative liabilities — current — 2,835 Interest rate swaps Derivative liabilities — non-current — 156 Total derivatives designated as hedges $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 9,586 Commodity derivatives Derivative liabilities — non-current — 12,706 Total derivatives not designated as hedges $ — $ 22,292 As of September 30, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,181 $ — Commodity derivatives Derivative assets — non-current 2,083 — Commodity derivatives Derivative liabilities — current — 375 Commodity derivatives Derivative liabilities — non-current — 92 Interest rate swaps Derivative liabilities — current — 3,312 Interest rate swaps Derivative liabilities — non-current — 722 Total derivatives designated as hedges $ 11,264 $ 4,501 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 8,427 Commodity derivatives Derivative liabilities — non-current — 12,895 Total derivatives not designated as hedges $ — $ 21,322 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments: | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 14 , were as follows (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 62,964 $ 62,964 $ 456,535 $ 456,535 $ 38,841 $ 38,841 Restricted cash and equivalents (a) $ 2,140 $ 2,140 $ 1,697 $ 1,697 $ 2,462 $ 2,462 Notes payable (a) $ 75,000 $ 75,000 $ 76,800 $ 76,800 $ 117,900 $ 117,900 Long-term debt, including current maturities, net of deferred financing costs (b) $ 3,217,511 $ 3,525,362 $ 1,853,682 $ 1,992,274 $ 1,553,167 $ 1,718,964 __________ (a) Carrying value approximates fair value due to either the 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. |
Other Comprehensive Income (Los
Other Comprehensive Income (Loss): | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Other Comprehensive Income (Loss) | OTHER COMPREHENSIVE INCOME (LOSS) The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended Nine Months Ended September 30, 2016 September 30, 2015 September 30, 2016 September 30, 2015 Gains and losses on cash flow hedges: Interest rate swaps Interest expense $ 840 $ 1,603 $ 2,530 $ 4,709 Commodity contracts Revenue (2,201 ) (3,109 ) (9,140 ) (10,707 ) Commodity contracts Fuel, purchased power and cost of natural gas sold (128 ) — 23 — (1,489 ) (1,506 ) (6,587 ) (5,998 ) Income tax Income tax benefit (expense) 566 558 2,450 2,548 Reclassification adjustments related to cash flow hedges, net of tax $ (923 ) $ (948 ) $ (4,137 ) $ (3,450 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) $ (165 ) $ (166 ) Actuarial gain (loss) Operations and maintenance 494 706 1,482 2,116 439 651 1,317 1,950 Income tax Income tax benefit (expense) (152 ) (228 ) (459 ) (684 ) Reclassification adjustments related to defined benefit plans, net of tax $ 287 $ 423 $ 858 $ 1,266 Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2014 $ (3,912 ) $ 9,005 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss), net of tax 332 263 395 990 Balance as of March 31, 2015 (3,580 ) 9,268 (19,742 ) (14,054 ) Other comprehensive income (loss), net of tax 503 (3,730 ) 422 (2,805 ) Balance as of June 30, 2015 (3,077 ) 5,538 (19,320 ) (16,859 ) Other comprehensive income (loss), net of tax 457 1,368 423 2,248 Ending Balance September 30, 2015 $ (2,620 ) $ 6,906 $ (18,897 ) $ (14,611 ) Balance as of December 31, 2015 $ 294 $ 6,431 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss), net of tax (11,171 ) (885 ) 286 (11,770 ) Balance as of March 31, 2016 (10,877 ) 5,546 (15,494 ) (20,825 ) Other comprehensive income (loss), net of tax (7,649 ) (3,575 ) 285 (10,939 ) Balance as of June 30, 2016 (18,526 ) 1,971 (15,209 ) (31,764 ) Other comprehensive income (loss), net of tax 244 (1,718 ) 287 (1,187 ) Ending Balance September 30, 2016 $ (18,282 ) $ 253 $ (14,922 ) $ (32,951 ) |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information: | 9 Months Ended |
Sep. 30, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine months ended September 30, 2016 September 30, 2015 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 44,140 $ 52,314 Increase (decrease) in capitalized assets associated with asset retirement obligations $ (2,285 ) $ — Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (82,639 ) $ (49,797 ) Income taxes, net $ (1,168 ) $ (1,202 ) |
Employee Benefit Plans_
Employee Benefit Plans: | 9 Months Ended |
Sep. 30, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS On February 12, 2016, as disclosed in Note 2 , we completed the acquisition of SourceGas, adding an additional defined benefit pension plan, two additional non-pension defined benefit postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement, among other factors. In accordance with ASC 715, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a Regulatory asset and will be amortized over the average remaining service life of the plans. Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Unfunded postretirement benefit obligation $ 22,187 $ 11,751 Defined Benefit Pension Plans We have three defined benefit pension plans for certain eligible employees consisting of the Black Hills Corporation pension plan, Black Hills Utility Holdings’ pension plan and the SourceGas retirement plan. The benefits for the pension plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. All Pension Plans have been closed to new employees and frozen for certain employees who did not meet age and service based criteria. 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. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income, regulatory assets or regulatory liabilities. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 service costs are 4.749% , 4.880% and 4.372% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The discount rates used to measure the 2016 interest costs are 3.827% , 3.817% and 3.284% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.575% for pension, 4.500% for supplemental non-qualified defined benefit and 4.165% for other postretirement benefit costs. The decrease in the total 2016 service and interest costs is approximately $2.8 million , $0.3 million and $0.4 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method. In connection with the acquisition related re-measurement of the SourceGas benefit plans we adopted the spot yield curve method, referenced above. The discount rates used to measure the 2016 interest costs are 3.690% for pension and 3.319% for other post retirement costs, effective February 11, 2016. The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 2,078 $ 1,494 $ 6,234 $ 4,482 Interest cost 3,936 3,880 11,808 11,640 Expected return on plan assets (5,766 ) (4,867 ) (17,297 ) (14,601 ) Prior service cost 15 15 45 45 Net loss (gain) 1,793 2,759 5,379 8,277 Net periodic benefit cost $ 2,056 $ 3,281 $ 6,169 $ 9,843 Defined Benefit Postretirement Healthcare Plans With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via Voluntary Employees’ Beneficiary Association, “VEBAs”. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 467 $ 464 $ 1,401 $ 1,392 Interest cost 485 450 1,455 1,350 Expected return on plan assets (70 ) (33 ) (210 ) (99 ) Prior service cost (benefit) (107 ) (107 ) (321 ) (321 ) Net loss (gain) 84 102 252 306 Net periodic benefit cost $ 859 $ 876 $ 2,577 $ 2,628 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 623 $ (84 ) $ 1,530 $ 799 Interest cost 314 364 943 1,092 Prior service cost 1 1 2 3 Net loss (gain) 207 270 621 810 Net periodic benefit cost $ 1,145 $ 551 $ 3,096 $ 2,704 Contributions We anticipate that we will make contributions to the benefit plans in 2016 and 2017 . Contributions to the Defined Benefit Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ 4,000 $ 14,200 $ — $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 3,576 $ 1,192 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 1,176 $ 392 $ 1,627 |
Commitments and Contingencies_
Commitments and Contingencies: | 9 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES There have been no significant changes to commitments and contingencies from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2015 Annual Report on Form 10-K except for those described below and in Notes 2 and 22 . Gas Supply Agreements Acquired Utilities In connection with the SourceGas Acquisition (see Note 2 ), we assumed various commitments relating to natural gas supply and transportation commitments and lease commitments, as summarized below (in thousands): 2016 2017 2018 2019 2020 Thereafter Total Future minimum payments Pipeline capacity obligations $ 9,718 $ 31,088 $ 34,676 $ 30,878 $ 30,878 $ 149,554 $ 286,792 Facilities and equipment 758 2,236 2,230 1,698 1,382 3,337 11,641 Total $ 10,476 $ 33,324 $ 36,906 $ 32,576 $ 32,260 $ 152,891 $ 298,433 Also due to the acquisition, there are other commitments to purchase natural gas to meet customer needs, which are short-term or long-term in nature. At September 30, 2016, the long-term commitments to purchase physical quantities of natural gas under contracts indexed to the following indices were as follows: MMBtu (in thousands) 2016 2017 2018 2019 2020 Total Natural Gas Indices Colorado Interstate Gas 1,355 6,684 — — — 8,039 Panhandle Eastern Pipeline 239 — — — — 239 Northwest Wyoming Pool 488 1,208 1,208 720 — 3,624 El Paso San Juan 98 270 — — — 368 Purchases under these contracts totaled $6.2 million for the nine months ended September 30, 2016, of which $1.6 million is recovered under the applicable states’ purchased-gas recovery mechanisms. Build Transfer Agreement On November 2, 2015, Colorado Electric executed a build-transfer agreement with Invenergy Wind Development Colorado, LLC to purchase the 60 MW, $109 million Peak View Wind Project. Peak View will be built by Invenergy Wind Development Colorado, LLC approximately 30 miles south of Pueblo, Colorado, in Huerfano and Las Animas counties. The estimated cost of $109 million includes taxes, transmission infrastructure and interconnection costs. Construction started in February of 2016 and is expected to be completed in late 2016. Under the build transfer agreement, Colorado Electric makes progress payments to Invenergy, which started in late 2015, and continue through completion of the project. Ownership of Peak View will transfer to Colorado Electric prior to commercial operation and will be operated as a utility-owned asset. BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric. At September 30, 2016 , the balance of BHC’s guarantee was approximately $24 million . The balance of the guarantee decreases as progress payments are made. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the second anniversary of the closing date. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of September 30, 2016 , we were in compliance with the debt covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at September 30, 2016 : • Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of September 30, 2016 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million . |
Impairment of Assets_
Impairment of Assets: | 9 Months Ended |
Sep. 30, 2016 | |
Asset Impairment Charges [Abstract] | |
Asset Impairment Charges [Text Block] | IMPAIRMENT OF ASSETS Long-lived Assets Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. In determining the ceiling value of our assets under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. As a result of continued low commodity prices in 2016 and throughout 2015, we recorded the following non-cash ceiling test impairments of our oil and gas assets included in our Oil and Gas segment for the three and nine months ended September 30, 2016 and September 30, 2015 . • During the three and nine months ended September 30, 2016, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $12 million and $38 million , respectively. At September 30, 2016, the average NYMEX natural gas price was $2.28 per Mcf, adjusted to $1.03 per Mcf at the wellhead; the average NYMEX crude oil price was $41.68 per barrel, adjusted to $35.88 per barrel at the wellhead. • During the three and nine months ended September 30, 2015, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $62 million and $178 million , respectively. At September 30, 2015, the average NYMEX natural gas price was $3.06 per Mcf, adjusted to $1.72 per Mcf at the wellhead; the average NYMEX crude oil price was $59.21 per barrel, adjusted to $52.82 per barrel at the wellhead. During the second quarter of 2016, we advanced our Oil and Gas strategy, identifying certain non-core assets which may be sold as they are not expected to be utilized in the Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million , in addition to the impairments noted above. Equity Investments in Unconsolidated Subsidiaries At June 30, 2015, our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. Due to sustained low commodity prices, recurring operating losses and future expectations, we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements. We valued this investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline is considered to be other than temporary. As a result we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million , the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system. |
Income Taxes_
Income Taxes: | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended September 30, Tax (benefit) expense (c) 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) (4.0 ) 4.7 Percentage depletion in excess of cost (2.3 ) 2.0 Accounting for uncertain tax positions adjustment (2.4 ) (1.2 ) Noncontrolling interest (b) (3.7 ) — Flow-through adjustments (2.2 ) 2.4 Inter-period adjustment 7.2 11.2 AFUDC equity (0.6 ) — Other tax differences 0.1 0.7 27.1 % 54.8 % __________ (a) The state income tax benefit is primarily attributable to favorable flow-through adjustments. (b) The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016. (c) The tax rate for the three months ended September 30, 2015 represents a tax benefit due to the net loss for the period. The lower pre-tax income for the third quarter of 2016 is causing some of the percentages to not be reflective of the expected impact on full year operating results. Nine Months Ended September 30, Tax (benefit) expense (e) 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 1.7 6.7 Percentage depletion in excess of cost (c) (9.7 ) 4.5 Inter-period adjustment 0.1 — Accounting for uncertain tax positions adjustment (d) (7.7 ) (4.7 ) Noncontrolling interest (2.5 ) — Transaction costs 1.4 — Flow-through adjustments (1.9 ) 4.7 Other tax differences (0.9 ) (1.3 ) 15.5 % 44.9 % _________ (c) The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (d) The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. (e) The tax rate for the nine months ended September 30, 2015 represents a tax benefit due to the net loss for the period. In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 million of the liability for unrecognized tax benefits, including interest, during the first quarter of 2016. The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $8.0 million excluding interest. |
Accrued Liabilities_
Accrued Liabilities: | 9 Months Ended |
Sep. 30, 2016 | |
Payables and Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities Disclosure [Text Block] | ACCRUED LIABILITIES The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Accrued employee compensation, benefits and withholdings $ 57,203 $ 43,342 $ 43,390 Accrued property taxes 37,156 32,393 30,669 Accrued payments related to litigation expenses and settlements — 38,750 33,375 Customer deposits and prepayments 51,137 53,496 33,225 Accrued interest and contract adjustment payments 42,612 25,762 22,839 CIAC current portion 5,465 14,745 16,604 Other (none of which is individually significant) 34,949 23,573 49,787 Total accrued liabilities $ 228,522 $ 232,061 $ 229,889 |
Management's Statement_ Managem
Management's Statement: Management's Statement (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Segment Reporting | Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. |
Business Combinations | Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition. |
Noncontrolling Interest | Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests. |
Share-Based Compensation | Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. |
Management's Statement_ Manag31
Management's Statement: Management's Statement (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Segment Reporting Reclassification | The following changes have been made to our Condensed Consolidated Statements of Income (Loss) to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three and nine months ended September 30, 2015 , respectively: For the Three Months Ended September 30, 2015 For the Nine Months Ended September 30, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 67,282 $ (67,282 ) $ — $ 205,630 $ (205,630 ) $ — Non-regulated energy operations and maintenance $ 22,548 $ (22,548 ) $ — $ 67,744 $ (67,744 ) $ — Operations and maintenance $ — $ 89,830 $ 89,830 $ — $ 273,374 $ 273,374 |
Acquisition_ Acquisition (Table
Acquisition: Acquisition (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Business Combinations [Abstract] | |
Business Combination, Separately Recognized Transactions | (in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration Paid, net of working capital adjustment received $ 1,124,238 Preliminary Allocation of Purchase Price: Current Assets $ 111,893 Property, plant & equipment, net 1,058,093 Goodwill 940,620 Deferred charges and other assets, excluding goodwill 133,215 Current liabilities (166,807 ) Long-term debt (764,337 ) Deferred credits and other liabilities (188,439 ) Total preliminary consideration paid, net of working-capital adjustment received $ 1,124,238 |
Business Combination, Pro Forma Information | The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Revenue $ 333,786 $ 344,498 $ 1,188,148 $ 1,320,047 Net income (loss) available for common stock $ 17,376 $ (14,189 ) $ 89,973 $ (13,884 ) Earnings (loss) per share, Basic $ 0.33 $ (0.28 ) $ 1.74 $ (0.27 ) Earnings (loss) per share, Diluted $ 0.32 $ (0.28 ) $ 1.70 $ (0.27 ) |
Business Segment Information_ B
Business Segment Information: Business Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting Information, Additional Information [Abstract] | |
Segment Reporting | Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended September 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 171,754 $ 2,747 $ 24,181 Gas (f) 141,445 — (2,939 ) Power Generation (e) 1,906 21,431 5,642 Mining 9,042 7,778 3,307 Oil and Gas (a) 9,639 — (8,828 ) Corporate activities (c) — — (7,232 ) Inter-company eliminations — (31,956 ) — Total $ 333,786 $ — $ 14,131 Three Months Ended September 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 176,042 $ 2,548 $ 22,659 Gas (d) 75,155 — 652 Power Generation 2,123 21,128 9,067 Mining 8,890 8,076 3,047 Oil and Gas (a) (b) 9,895 — (39,769 ) Corporate activities (c) — — (5,599 ) Inter-company eliminations — (31,752 ) — Total $ 272,105 $ — $ (9,943 ) Nine Months Ended September 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 493,845 $ 9,413 $ 62,625 Gas (f) 563,879 — 29,975 Power Generation (e) 5,304 63,055 19,907 Mining 20,498 23,651 6,969 Oil and Gas (a) 25,660 — (35,277 ) Corporate activities (c) — — (29,397 ) Inter-company eliminations — (96,119 ) — Total $ 1,109,186 $ — $ 54,802 Nine Months Ended September 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 504,049 $ 8,481 $ 57,844 Gas (d) 416,950 — 27,475 Power Generation 5,782 62,452 24,761 Mining 26,084 23,541 9,106 Oil and Gas (a) (b) 33,481 — (130,079 ) Corporate activities (c) — — (7,042 ) Inter-company eliminations — (94,474 ) — Total $ 986,346 $ — $ (17,935 ) ___________ (a) Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million and $36 million and $113 million , respectively. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) available for common stock for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million . See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $4.0 million and $24 million ; and $2.8 million and $3.0 million respectively, and after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million ; and $1.2 million and $1.8 million respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $6.2 million and $31 million , respectively, and Net loss of $1.0 million and Net income of $0.5 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (e) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.8 million and $6.4 million for the three and nine months ended September 30, 2016 . (f) Gas Utility revenue increased for the three and nine months ended September 30, 2016 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016. |
Reconciliation of Assets from Segment to Consolidated | Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: September 30, 2016 December 31, 2015 September 30, 2015 Segment: Electric (a) (b) $ 2,824,145 $ 2,720,004 $ 2,706,654 Gas (b) (e) 3,182,852 999,778 967,225 Power Generation (a) 77,570 60,864 78,666 Mining 66,804 76,357 78,000 Oil and Gas (c) 158,970 208,956 280,842 Corporate activities (d) 141,795 576,358 120,545 Total assets $ 6,452,136 $ 4,642,317 $ 4,231,932 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $136 million , respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and September 30, 2015 . (c) As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $52 million for the nine months ended September 30, 2016 , $250 million for the year ended December 31, 2015 , and $178 million for the nine months ended September 30, 2015 . See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016. (e) Includes the assets acquired in the SourceGas acquisition on February 12, 2016. |
Accounts Receivable_ Accounts R
Accounts Receivable: Accounts Receivable (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Receivables [Abstract] | |
Accounts Receivable and Allowance for Doubtful Accounts | Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts September 30, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 44,747 $ 30,970 $ (580 ) $ 75,137 Gas Utilities 48,057 23,582 (1,923 ) 69,716 Power Generation 1,165 — — 1,165 Mining 3,612 — — 3,612 Oil and Gas 3,341 — (13 ) 3,328 Corporate 1,659 — — 1,659 Total $ 102,581 $ 54,552 $ (2,516 ) $ 154,617 Accounts Unbilled Less Allowance for Accounts December 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,331 32,869 (1,001 ) 62,199 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,025 — — 1,025 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 Accounts Unbilled Less Allowance for Accounts September 30, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,655 $ 33,979 $ (811 ) $ 74,823 Gas Utilities (a) 20,031 11,230 (527 ) 30,734 Power Generation 1,186 — — 1,186 Mining 2,684 — — 2,684 Oil and Gas 4,522 — (13 ) 4,509 Corporate 1,566 — — 1,566 Total $ 71,644 $ 45,209 $ (1,351 ) $ 115,502 ___________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $2.9 million as of December 31, 2015 and September 30, 2015 , respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment. |
Regulatory Accounting_ Regulato
Regulatory Accounting: Regulatory Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) September 30, 2016 December 31, 2015 September 30, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 16,525 $ 24,751 $ 25,354 Deferred gas cost adjustments (a)(d) 1 12,172 15,521 9,358 Gas price derivatives (a) 7 14,405 23,583 23,681 AFUDC (b) 45 14,093 12,870 12,580 Employee benefit plans (c) (e) 12 107,578 83,986 95,779 Environmental (a) subject to approval 1,126 1,180 1,209 Asset retirement obligations (a) 44 507 457 675 Loss on reacquired debt (a) 30 15,918 3,133 3,169 Renewable energy standard adjustment (b) 5 1,694 5,068 5,102 Flow through accounting (c) 35 33,136 29,722 28,585 Decommissioning costs (f) 10 17,271 18,310 16,353 Gas supply contract termination 5 28,164 — — Other regulatory assets (a) 15 22,212 13,903 12,454 $ 284,801 $ 232,484 $ 234,299 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 15,033 $ 7,814 $ 9,899 Employee benefit plans (c) (e) 12 65,575 47,218 53,140 Cost of removal (a) 44 114,616 90,045 86,946 Other regulatory liabilities (c) 25 8,197 7,964 7,826 $ 203,421 $ 153,041 $ 157,811 __________ (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) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. (e) Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs. Loss on reacquired debt - The increase from the prior periods is the loss on the early retirement of debt assumed in the SourceGas Acquisition. These costs are being amortized to interest expense over a maximum period of 30 years. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We terminated the contract and settled the liability on April 29, 2016. Cost of Removal - Cost of Removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense. The increase from the prior periods is primarily due to cost of removal recorded with the SourceGas purchase price allocation. |
Materials, Supplies and Fuel_ M
Materials, Supplies and Fuel: Materials, Supplies and Fuel (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Inventory, Net [Abstract] | |
Materials, Supplies and Fuel | The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Materials and supplies $ 67,257 $ 55,726 $ 53,838 Fuel - Electric Utilities 4,282 5,567 6,139 Natural gas in storage held for distribution 41,936 25,650 30,372 Total materials, supplies and fuel $ 113,475 $ 86,943 $ 90,349 |
Goodwill & Intangible Assets_ G
Goodwill & Intangible Assets: Goodwill & Intangible Assets (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of Goodwill | Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 256,850 $ 94,144 $ 8,765 $ 359,759 Acquisition of SourceGas (a) — 940,620 — 940,620 Ending balance at September 30, 2016 $ 256,850 $ 1,034,764 $ 8,765 $ 1,300,379 __________ (a) Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. (b) Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details. |
Schedule of Indefinite-Lived Intangible Assets | Intangible assets, net beginning balance at December 31, 2015 $ 3,380 Additions/amortization, net (a) 5,564 Intangible assets, net, ending balance at September 30, 2016 $ 8,944 __________ (a) Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10 -year estimated useful lives. See Note 2 for more information. |
Asset Retirement Obligations_ A
Asset Retirement Obligations: Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following table presents the details of asset retirement obligations which are included on the accompanying Condensed Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b) (c) September 30, 2016 Electric Utilities $ 4,462 $ — $ — $ 143 $ — $ 11 $ 4,616 Gas Utilities 136 — — 478 22,412 6,436 29,462 Mining 18,633 — (15 ) 653 — (5,603 ) 13,668 Oil and Gas 21,504 — (814 ) 1,047 — 57 21,794 Total $ 44,735 $ — $ (829 ) $ 2,321 $ 22,412 $ 901 $ 69,540 __________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. |
Earnings Per Share_ Earnings Pe
Earnings Per Share: Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share Reconciliation | A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Net income (loss) available for common stock $ 14,131 $ (9,943 ) $ 54,802 $ (17,935 ) Weighted average shares - basic 52,184 44,635 51,583 44,598 Dilutive effect of: Equity Units (a) 1,414 — 1,191 — Equity compensation 135 — 119 — Weighted average shares - diluted (b) 53,733 44,635 52,893 44,598 __________ (a) Calculated using the treasury stock method. (b) Due to our net loss for the three and nine months ended September 30, 2015 , potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015 , respectively. |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Equity compensation 2 121 4 114 Anti-dilutive shares 2 121 4 114 |
Notes Payable_ Notes Payable an
Notes Payable: Notes Payable and Long-term Debt (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Short-term Debt | We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 75,000 $ 30,500 $ 76,800 $ 33,399 $ 117,900 $ 30,600 |
Schedule of Credit Facility Covenants | our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: As of September 30, 2016 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 68% Less than 70% |
Long-Term Debt And Current Ma41
Long-Term Debt And Current Maturities Of Long-Term Debt: Long-Term Debt And Current Maturities Of Long-Term Debt (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt was as follows (dollars in thousands): Interest Rate at September 30, 2016 September 30, 2016 December 31, 2015 September 30, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (842 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,685 ) (1,890 ) (1,959 ) Senior unsecured notes due July 15, 2020 5.88% 200,000 200,000 200,000 Senior unsecured notes due January 11, 2019 2.50% 250,000 — — Unamortized discount on Senior unsecured notes due 2019 (205 ) — — Senior unsecured notes due January 15, 2027 3.15% 400,000 — — Unamortized discount on Senior unsecured notes due 2027 (202 ) — — Senior unsecured notes, due September 15, 2046 4.20% 300,000 — — Unamortized discount on Senior unsecured notes due 2046 (1,630 ) — — Corporate term loan due August 9, 2019 (a) 1.46% 400,000 — — Corporate term loan due April 12, 2017 (a) — 300,000 300,000 Corporate term loan due June 7, 2021 2.32% 25,842 — — Total Corporate Debt 2,695,278 1,322,110 1,023,041 Electric Utilities First Mortgage Bonds due October 20, 2044 4.43% 85,000 85,000 85,000 First Mortgage Bonds due October 20, 2044 4.53% 75,000 75,000 75,000 First Mortgage Bonds due August 15, 2032 7.23% 75,000 75,000 75,000 First Mortgage Bonds due November 1, 2039 6.13% 180,000 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (96 ) (99 ) (99 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (b) 0.86% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (b) 0.86% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (b) 1.01% 2,855 2,855 2,855 Total Electric Utilities Debt 544,759 544,756 544,756 Total long-term debt 3,240,037 1,866,866 1,567,797 Less current maturities 5,743 — — Less deferred financing costs (c) 22,526 13,184 14,630 Long-term debt, net of current maturities $ 3,211,768 $ 1,853,682 $ 1,553,167 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) Variable interest rate. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $2.5 million , $1.7 million and $1.9 million as of September 30, 2016 , December 31, 2015 and September 30, 2015 , respectively. |
Schedule of Maturities of Long-term Debt | Scheduled future maturities of debt, excluding amortization of premiums or discounts are (in thousands): Year Ended: 2016 $ 1,436 2017 $ 5,743 2018 $ 5,743 2019 $ 655,743 2020 $ 205,742 Thereafter $ 2,370,290 |
Schedule Of Long-Term Debt Due In The Next Twelve Months | As of September 30, 2016 , we have the following classified as Current maturities of long-term debt: Loan Interest Rate Current Maturities at September 30, 2016 Corporate Corporate term loan due June 7, 2021 (a) 2.32% 5,743 Current Maturities of Long-Term Debt $ 5,743 _______________ (a) Principal payments of $1.4 million are due quarterly . |
Equity_ Equity (Tables)
Equity: Equity (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Stockholders' Equity [Abstract] | |
Schedule of Stockholders Equity | A summary of the changes in equity is as follows: Nine Months Ended September 30, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 $ — $ 1,465,867 Net income (loss) 54,802 6,402 61,204 Other comprehensive income (loss) (23,896 ) — (23,896 ) Dividends on common stock (65,247 ) — (65,247 ) Share-based compensation 3,822 — 3,822 Issuance of common stock 105,238 — 105,238 Dividend reinvestment and stock purchase plan 2,242 — 2,242 Other stock transactions (24 ) — (24 ) Sale of noncontrolling interest 61,838 115,496 177,334 Distribution to noncontrolling interest — (4,516 ) $ (4,516 ) Balance at September 30, 2016 $ 1,604,642 $ 117,382 $ 1,722,024 Nine Months Ended September 30, 2015 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 $ — $ 1,353,884 Net income (loss) (17,935 ) — (17,935 ) Other comprehensive income (loss) 433 — 433 Dividends on common stock (54,450 ) — (54,450 ) Share-based compensation 2,998 — 2,998 Issuance of common stock — — — Dividend reinvestment and stock purchase plan 2,298 — 2,298 Other stock transactions (16 ) — (16 ) Balance at September 30, 2015 $ 1,287,212 $ — $ 1,287,212 |
Schedule of Variable Interest Entities | We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of: September 30, 2016 December 31, 2015 September 30, 2015 (in thousands) Assets Current assets $ 14,191 $ — $ — Property, plant and equipment of variable interest entities, net $ 220,818 $ — $ — Liabilities Current liabilities $ 3,353 $ — $ — |
Risk Management Activities_ Ris
Risk Management Activities: Risk Management Activities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments | The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Interest Rate Swaps (b) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (b) Notional $ 75,000 $ 250,000 $ 75,000 $ 75,000 Weighted average fixed interest rate 4.97 % 2.29 % 4.97 % 4.97 % Maximum terms in years 0.33 1.33 1.00 1.33 Derivative assets, non-current $ — $ 3,441 $ — $ — Derivative liabilities, current $ 654 $ — $ 2,835 $ 3,312 Derivative liabilities, non-current $ — $ — $ 156 $ 722 __________ (a) These swaps were settled in August 2016 in conjunction with the refinancing of acquired SourceGas debt. (b) These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings. |
Contract or Notional Amounts and Terms of Commodity Derivatives | The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in a net long position as of: September 30, 2016 December 31, 2015 September 30, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 17,740,000 51 20,580,000 60 17,180,000 63 Natural gas options purchased, net (b) 6,540,000 17 2,620,000 3 6,300,000 6 Natural gas basis swaps purchased 13,650,000 51 18,150,000 60 12,980,000 51 Natural gas fixed for float swaps, net (c) 4,749,000 20 — 0 — 0 Natural gas physical commitments, net 15,666,202 13 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of September 30, 2016 is net of 2,306,000 MMBtus of collar options (call purchase and put sale) transactions. (c) 2,640,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased. |
Derivative Instruments, Gain (Loss) | The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended September 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (465 ) Interest expense $ 840 Interest expense $ — Commodity derivatives 727 Revenue (2,201 ) Revenue — Commodity derivatives (553 ) Fuel, purchased power and cost of natural gas sold (128 ) Fuel, purchased power and cost of natural gas sold — Total $ (291 ) $ (1,489 ) $ — Three Months Ended September 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (898 ) Interest expense $ 1,603 Interest expense $ — Commodity derivatives 5,280 Revenue (3,109 ) Revenue — Total $ 4,382 $ (1,506 ) $ — Nine Months Ended September 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (31,130 ) Interest expense $ 2,530 Interest expense $ — Commodity derivatives (312 ) Revenue (9,140 ) Revenue — Commodity derivatives 220 Fuel, purchased power and cost of natural gas sold 23 Fuel, purchased power and cost of natural gas sold — Total $ (31,222 ) $ (6,587 ) $ — Nine Months Ended September 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (2,674 ) Interest expense $ 4,709 Interest expense $ — Commodity derivatives 6,800 Revenue (10,707 ) Revenue — Total $ 4,126 $ (5,998 ) $ — |
Oil and Gas [Member] | |
Derivative [Line Items] | |
Schedule of Derivative Instruments | We had the following short positions as of: September 30, 2016 December 31, 2015 September 30, 2015 Crude Oil Futures Natural Gas Futures and Swaps Call Options Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 159,000 1,625,000 36,000 198,000 4,392,500 258,000 5,392,500 Maximum terms in months (b) 27 15 15 24 24 27 27 __________ (a) Crude oil futures and call options in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged. |
Fair Value Measurements_ Fair V
Fair Value Measurements: Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value Hierarchy, Measured on Recurring Basis | The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of September 30, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 2,882 $ — $ — $ 2,882 Commodity derivatives — Utilities — 5,330 — (3,647 ) 1,683 Interest Rate Swaps — — — — — Total $ — $ 8,212 $ — $ (3,647 ) $ 4,565 Liabilities: Commodity derivatives — Oil and Gas $ — $ 705 $ — $ — $ 705 Commodity derivatives — Utilities — 16,130 — (15,231 ) 899 Interest rate swaps — 654 — — 654 Total $ — $ 17,489 $ — $ (15,231 ) $ 2,258 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 10,644 $ — $ (10,644 ) $ — Commodity derivatives —Utilities — 2,293 — (2,293 ) — Interest Rate Swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives — Oil and Gas $ — $ 556 $ — $ (556 ) $ — Commodity derivatives — Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of September 30, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 11,264 $ — $ (11,264 ) $ — Commodity derivatives — Utilities — 3,123 — (3,123 ) — Interest Rate Swaps — — — — — Total $ — $ 14,387 $ — $ (14,387 ) $ — Liabilities: Commodity derivatives — Oil and Gas $ — $ 467 $ — $ (467 ) $ — Commodity derivatives — Utilities — 24,445 — (24,445 ) — Interest rate swaps — 4,034 — — 4,034 Total $ — $ 28,946 $ — $ (24,912 ) $ 4,034 |
Schedule of Derivative Instruments Balance Sheet Location | The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of September 30, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2,919 $ — Commodity derivatives Derivative assets — non-current 66 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 479 Commodity derivatives Derivative liabilities — non-current — 256 Interest rate swaps Derivative liabilities — current — 654 Interest rate swaps Derivative liabilities — non-current — — Total derivatives designated as hedges $ 2,985 $ 1,389 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,463 $ — Commodity derivatives Derivative assets — non-current 117 — Commodity derivatives Derivative liabilities — current — 808 Commodity derivatives Derivative liabilities — non-current — 61 Total derivatives not designated as hedges $ 1,580 $ 869 As of December 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,981 $ — Commodity derivatives Derivative assets — non-current 663 — Interest rate swaps Derivative assets — non-current 3,441 — Commodity derivatives Derivative liabilities — current — 465 Commodity derivatives Derivative liabilities — non-current — 91 Interest rate swaps Derivative liabilities — current — 2,835 Interest rate swaps Derivative liabilities — non-current — 156 Total derivatives designated as hedges $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 9,586 Commodity derivatives Derivative liabilities — non-current — 12,706 Total derivatives not designated as hedges $ — $ 22,292 As of September 30, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,181 $ — Commodity derivatives Derivative assets — non-current 2,083 — Commodity derivatives Derivative liabilities — current — 375 Commodity derivatives Derivative liabilities — non-current — 92 Interest rate swaps Derivative liabilities — current — 3,312 Interest rate swaps Derivative liabilities — non-current — 722 Total derivatives designated as hedges $ 11,264 $ 4,501 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 8,427 Commodity derivatives Derivative liabilities — non-current — 12,895 Total derivatives not designated as hedges $ — $ 21,322 |
Fair Value of Financial Instr45
Fair Value of Financial Instruments: Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 14 , were as follows (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 62,964 $ 62,964 $ 456,535 $ 456,535 $ 38,841 $ 38,841 Restricted cash and equivalents (a) $ 2,140 $ 2,140 $ 1,697 $ 1,697 $ 2,462 $ 2,462 Notes payable (a) $ 75,000 $ 75,000 $ 76,800 $ 76,800 $ 117,900 $ 117,900 Long-term debt, including current maturities, net of deferred financing costs (b) $ 3,217,511 $ 3,525,362 $ 1,853,682 $ 1,992,274 $ 1,553,167 $ 1,718,964 __________ (a) Carrying value approximates fair value due to either the 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. |
Other Comprehensive Income (L46
Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Reclassification Out of Accumulated Other Comprehensive Income (Loss) | The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended Nine Months Ended September 30, 2016 September 30, 2015 September 30, 2016 September 30, 2015 Gains and losses on cash flow hedges: Interest rate swaps Interest expense $ 840 $ 1,603 $ 2,530 $ 4,709 Commodity contracts Revenue (2,201 ) (3,109 ) (9,140 ) (10,707 ) Commodity contracts Fuel, purchased power and cost of natural gas sold (128 ) — 23 — (1,489 ) (1,506 ) (6,587 ) (5,998 ) Income tax Income tax benefit (expense) 566 558 2,450 2,548 Reclassification adjustments related to cash flow hedges, net of tax $ (923 ) $ (948 ) $ (4,137 ) $ (3,450 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) $ (165 ) $ (166 ) Actuarial gain (loss) Operations and maintenance 494 706 1,482 2,116 439 651 1,317 1,950 Income tax Income tax benefit (expense) (152 ) (228 ) (459 ) (684 ) Reclassification adjustments related to defined benefit plans, net of tax $ 287 $ 423 $ 858 $ 1,266 |
Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2014 $ (3,912 ) $ 9,005 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss), net of tax 332 263 395 990 Balance as of March 31, 2015 (3,580 ) 9,268 (19,742 ) (14,054 ) Other comprehensive income (loss), net of tax 503 (3,730 ) 422 (2,805 ) Balance as of June 30, 2015 (3,077 ) 5,538 (19,320 ) (16,859 ) Other comprehensive income (loss), net of tax 457 1,368 423 2,248 Ending Balance September 30, 2015 $ (2,620 ) $ 6,906 $ (18,897 ) $ (14,611 ) Balance as of December 31, 2015 $ 294 $ 6,431 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss), net of tax (11,171 ) (885 ) 286 (11,770 ) Balance as of March 31, 2016 (10,877 ) 5,546 (15,494 ) (20,825 ) Other comprehensive income (loss), net of tax (7,649 ) (3,575 ) 285 (10,939 ) Balance as of June 30, 2016 (18,526 ) 1,971 (15,209 ) (31,764 ) Other comprehensive income (loss), net of tax 244 (1,718 ) 287 (1,187 ) Ending Balance September 30, 2016 $ (18,282 ) $ 253 $ (14,922 ) $ (32,951 ) |
Supplemental Disclosure of Ca47
Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Nine months ended September 30, 2016 September 30, 2015 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 44,140 $ 52,314 Increase (decrease) in capitalized assets associated with asset retirement obligations $ (2,285 ) $ — Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (82,639 ) $ (49,797 ) Income taxes, net $ (1,168 ) $ (1,202 ) |
Employee Benefit Plans_ Employe
Employee Benefit Plans: Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Schedule of Defined Benefit Plans Disclosures | Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Unfunded postretirement benefit obligation $ 22,187 $ 11,751 |
Schedule of Net Benefit Costs | The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 2,078 $ 1,494 $ 6,234 $ 4,482 Interest cost 3,936 3,880 11,808 11,640 Expected return on plan assets (5,766 ) (4,867 ) (17,297 ) (14,601 ) Prior service cost 15 15 45 45 Net loss (gain) 1,793 2,759 5,379 8,277 Net periodic benefit cost $ 2,056 $ 3,281 $ 6,169 $ 9,843 Defined Benefit Postretirement Healthcare Plans With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via Voluntary Employees’ Beneficiary Association, “VEBAs”. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 467 $ 464 $ 1,401 $ 1,392 Interest cost 485 450 1,455 1,350 Expected return on plan assets (70 ) (33 ) (210 ) (99 ) Prior service cost (benefit) (107 ) (107 ) (321 ) (321 ) Net loss (gain) 84 102 252 306 Net periodic benefit cost $ 859 $ 876 $ 2,577 $ 2,628 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Service cost $ 623 $ (84 ) $ 1,530 $ 799 Interest cost 314 364 943 1,092 Prior service cost 1 1 2 3 Net loss (gain) 207 270 621 810 Net periodic benefit cost $ 1,145 $ 551 $ 3,096 $ 2,704 |
Schedule of Defined Benefit Plans Contributions | Contributions and anticipated contributions are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ 4,000 $ 14,200 $ — $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 3,576 $ 1,192 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 1,176 $ 392 $ 1,627 |
Commitments and Contingencies_
Commitments and Contingencies: Commitment and Contingency (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Supply Commitment | we assumed various commitments relating to natural gas supply and transportation commitments and lease commitments, as summarized below (in thousands): 2016 2017 2018 2019 2020 Thereafter Total Future minimum payments Pipeline capacity obligations $ 9,718 $ 31,088 $ 34,676 $ 30,878 $ 30,878 $ 149,554 $ 286,792 Facilities and equipment 758 2,236 2,230 1,698 1,382 3,337 11,641 Total $ 10,476 $ 33,324 $ 36,906 $ 32,576 $ 32,260 $ 152,891 $ 298,433 |
Long-term Purchase Commitment | At September 30, 2016, the long-term commitments to purchase physical quantities of natural gas under contracts indexed to the following indices were as follows: MMBtu (in thousands) 2016 2017 2018 2019 2020 Total Natural Gas Indices Colorado Interstate Gas 1,355 6,684 — — — 8,039 Panhandle Eastern Pipeline 239 — — — — 239 Northwest Wyoming Pool 488 1,208 1,208 720 — 3,624 El Paso San Juan 98 270 — — — 368 |
Income Taxes_ Income Taxes (Tab
Income Taxes: Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation | INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended September 30, Tax (benefit) expense (c) 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) (4.0 ) 4.7 Percentage depletion in excess of cost (2.3 ) 2.0 Accounting for uncertain tax positions adjustment (2.4 ) (1.2 ) Noncontrolling interest (b) (3.7 ) — Flow-through adjustments (2.2 ) 2.4 Inter-period adjustment 7.2 11.2 AFUDC equity (0.6 ) — Other tax differences 0.1 0.7 27.1 % 54.8 % __________ (a) The state income tax benefit is primarily attributable to favorable flow-through adjustments. (b) The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016. (c) The tax rate for the three months ended September 30, 2015 represents a tax benefit due to the net loss for the period. The lower pre-tax income for the third quarter of 2016 is causing some of the percentages to not be reflective of the expected impact on full year operating results. Nine Months Ended September 30, Tax (benefit) expense (e) 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 1.7 6.7 Percentage depletion in excess of cost (c) (9.7 ) 4.5 Inter-period adjustment 0.1 — Accounting for uncertain tax positions adjustment (d) (7.7 ) (4.7 ) Noncontrolling interest (2.5 ) — Transaction costs 1.4 — Flow-through adjustments (1.9 ) 4.7 Other tax differences (0.9 ) (1.3 ) 15.5 % 44.9 % |
Accrued Liabilities_ Accrued Li
Accrued Liabilities: Accrued Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Payables and Accruals [Abstract] | |
Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2016 December 31, 2015 September 30, 2015 Accrued employee compensation, benefits and withholdings $ 57,203 $ 43,342 $ 43,390 Accrued property taxes 37,156 32,393 30,669 Accrued payments related to litigation expenses and settlements — 38,750 33,375 Customer deposits and prepayments 51,137 53,496 33,225 Accrued interest and contract adjustment payments 42,612 25,762 22,839 CIAC current portion 5,465 14,745 16,604 Other (none of which is individually significant) 34,949 23,573 49,787 Total accrued liabilities $ 228,522 $ 232,061 $ 229,889 |
Management's Statement_ Segment
Management's Statement: Segment Reporting (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Prior Period Reclassification Adjustment | $ 89,830 | $ 273,374 | ||
Utilities - Operating and maintenance | 0 | 0 | ||
Operating Costs, Nonregulated Energy Operations | 0 | 0 | ||
Operations and maintenance | $ 115,103 | 89,830 | $ 334,706 | 273,374 |
Scenario, Previously Reported [Member] | ||||
Prior Period Reclassification Adjustment | 0 | 0 | ||
Utilities Group [Member] | ||||
Prior Period Reclassification Adjustment | (67,282) | (205,630) | ||
Utilities Group [Member] | Scenario, Previously Reported [Member] | ||||
Prior Period Reclassification Adjustment | 67,282 | 205,630 | ||
Non Regulated Energy Group [Member] | ||||
Prior Period Reclassification Adjustment | (22,548) | (67,744) | ||
Non Regulated Energy Group [Member] | Scenario, Previously Reported [Member] | ||||
Prior Period Reclassification Adjustment | $ 22,548 | $ 67,744 |
Management's Statement_ Simplif
Management's Statement: Simplifying The Presentation Of Debt Issuance Costs (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Sep. 30, 2015 |
Deferred Finance Costs [Member] | ||
Prior Period Reclassification Adjustment | $ 13 | $ 15 |
Acquisition_ Acquisition (Detai
Acquisition: Acquisition (Details) $ / shares in Units, $ in Thousands | Apr. 29, 2016USD ($)$ / Btu | Feb. 12, 2016USD ($)customerutilitymi | Jan. 13, 2016USD ($) | Nov. 23, 2015USD ($)shares | Sep. 30, 2016USD ($)$ / shares | Sep. 30, 2015USD ($)$ / shares | Sep. 30, 2016USD ($)$ / shares | Sep. 30, 2015USD ($)$ / shares | Dec. 31, 2015USD ($) | |
Acquisition Narrative [Abstract] | ||||||||||
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions | 99.50% | |||||||||
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired, Before Working Capital Adjustment | $ 1,135,000 | |||||||||
Proceeds From Issuance Of Common Stock and Sale Of Interest In Corporate Units | $ 536,000 | |||||||||
Long-term debt - issuances | $ 546,000 | 1,767,608 | $ 300,000 | |||||||
Revenue | $ 333,786 | $ 272,105 | 1,109,186 | 986,346 | ||||||
Net income (loss) available for common stock | 14,131 | (9,943) | 54,802 | (17,935) | ||||||
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired | 1,124,238 | 0 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital Adjustment To Goodwill | $ 5,800 | |||||||||
Acquisition Recap [Abstract] | ||||||||||
Goodwill | $ 940,620 | 1,300,379 | 359,527 | 1,300,379 | 359,527 | $ 359,759 | ||||
Settlement of Gas Supply Contract [Abstract] | ||||||||||
Early Termination Settlement of Gas Supply Contract | $ 40,000 | |||||||||
Percentage Of Contract Committed To Distribution Customers | 75.00% | |||||||||
Percentage Of Contract Not Subject to Regulatory Recovery | 25.00% | |||||||||
Regulatory Assets | $ 284,801 | 234,299 | $ 284,801 | 234,299 | 232,484 | |||||
Business Acquisition, Pro Forma Information [Abstract] | ||||||||||
Pro Forma - Combined Federal and State income Tax Rate | 37.00% | |||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 0.50% | 0.50% | ||||||||
Gas Supply Contract Termination [Member] | ||||||||||
Settlement of Gas Supply Contract [Abstract] | ||||||||||
Regulatory Assets | $ 30,000 | $ 28,164 | 0 | $ 28,164 | 0 | $ 0 | ||||
Regulatory Assets Amortization Period, Unclassified | 5 years | 5 years | ||||||||
Minimum [Member] | ||||||||||
Settlement of Gas Supply Contract [Abstract] | ||||||||||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 6 | |||||||||
Maximum [Member] | ||||||||||
Settlement of Gas Supply Contract [Abstract] | ||||||||||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 8 | |||||||||
Corporate[Member] | ||||||||||
Acquisition Narrative [Abstract] | ||||||||||
Business Acquisition, Transaction Costs | 5,200 | 4,300 | $ 36,000 | 5,000 | ||||||
Revenue | 0 | 0 | 0 | 0 | ||||||
Net income (loss) available for common stock | [1] | (7,232) | (5,599) | (29,397) | (7,042) | |||||
Remarketable Junior Subordinated Notes Due 2028 [Member] | ||||||||||
Acquisition Narrative [Abstract] | ||||||||||
Debt Instrument, Convertible, Number of Equity Instruments | shares | 5,980,000 | |||||||||
Common Stock [Member] | ||||||||||
Acquisition Narrative [Abstract] | ||||||||||
Stock Issued During Period, Shares, New Issues | shares | 6,325,000 | |||||||||
Source Gas [Member] | ||||||||||
Acquisition Narrative [Abstract] | ||||||||||
Number Of Natural Gas Utilities Acquired | utility | 4 | |||||||||
Number Of Customers Acquired | customer | 429,000 | |||||||||
Length Of Natural Gas Pipeline Acquired | mi | 512 | |||||||||
Revenue | 72,000 | 217,000 | ||||||||
Net income (loss) available for common stock | (3,800) | 800 | ||||||||
Goodwill, Expected Tax Deductible Amount | 251,000 | 251,000 | ||||||||
Acquisition Recap [Abstract] | ||||||||||
Preliminary Purchase Price | $ 1,894,882 | |||||||||
Less: Long-term debt assumed | (760,000) | |||||||||
Less: Working capital adjustment received | (10,644) | |||||||||
Consideration Paid, net of working capital adjustment received | 1,124,238 | |||||||||
Current Assets | 111,893 | |||||||||
Property, plant & equipment, net | 1,058,093 | |||||||||
Deferred charges and other assets, excluding goodwill | 133,215 | |||||||||
Current liabilities | (166,807) | |||||||||
Long-term debt | (764,337) | |||||||||
Deferred credits and other liabilities | $ (188,439) | |||||||||
Business Acquisition, Pro Forma Information [Abstract] | ||||||||||
Pro Forma - Revenue | 333,786 | 344,498 | 1,188,148 | 1,320,047 | ||||||
Pro Forma - Net income (loss) available for common stock | $ 17,376 | $ (14,189) | $ 89,973 | $ (13,884) | ||||||
Pro Forma - Earnings per share, Basic (usd per share) | $ / shares | $ 0.33 | $ (0.28) | $ 1.74 | $ (0.27) | ||||||
Pro Forma - Earnings per share, Diluted (usd per share) | $ / shares | $ 0.32 | $ (0.28) | $ 1.70 | $ (0.27) | ||||||
Source Gas [Member] | Black Hills Energy, Arkansas [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Duration Of Base Rate Moratorium Imposed by ASPC | 12 months | |||||||||
Annual Amount of Customer Credit | $ 250 | |||||||||
Source Gas [Member] | Black Hills Energy, Arkansas [Member] | Maximum [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Duration Of Annual Customer Credit | 5 years | |||||||||
Source Gas [Member] | Black Hills Gas Distribution, Colorado [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Annual Amount of Customer Credit | $ 200 | |||||||||
Duration of Base Rate Moratorium imposed by CPUC | 3 years | |||||||||
Source Gas [Member] | Black Hills Gas Distribution, Colorado [Member] | Maximum [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Duration Of Annual Customer Credit | 5 years | |||||||||
Source Gas [Member] | Black Hills Gas Distribution - Nebraska [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Duration of Base Rate Moratorium imposed by NPSC | 3 years | |||||||||
Continuation Period of Choice Gas Program | 3 years | |||||||||
Source Gas [Member] | Rocky Mountain Natural Gas [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Duration of Base Rate Moratorium imposed by CPUC | 2 years | |||||||||
Source Gas [Member] | Black Hills Gas Distribution - Wyoming [Member] | ||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | ||||||||||
Continuation Period of Choice Gas Program | 3 years | |||||||||
[1] | Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $4.0 million and $24 million; and $2.8 million and $3.0 million respectively, and after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million; and $1.2 million and $1.8 million respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
Business Segment Information_ I
Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||||||
Segment Reporting Information | |||||||||
Revenue | $ 333,786 | $ 272,105 | $ 1,109,186 | $ 986,346 | |||||
Net income (loss) available for common stock | 14,131 | (9,943) | 54,802 | (17,935) | |||||
Equity Method Investment, Other than Temporary Impairment, Net of Income Taxes | 3,400 | ||||||||
Prior Period Reclassification Adjustment | 89,830 | 273,374 | |||||||
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest | 3,753 | 0 | 6,415 | 0 | |||||
Revenue [Member] | |||||||||
Segment Reporting Information | |||||||||
Prior Period Reclassification Adjustment | 6,200 | 31,000 | |||||||
Net Income (Loss) Available to Common Stockholders, Basic [Member] | |||||||||
Segment Reporting Information | |||||||||
Prior Period Reclassification Adjustment | 1,000 | 500 | |||||||
Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | (31,956) | (31,752) | (96,119) | (94,474) | |||||
Net income (loss) available for common stock | 0 | 0 | 0 | 0 | |||||
Corporate[Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 0 | 0 | 0 | 0 | |||||
Net income (loss) available for common stock | [1] | (7,232) | (5,599) | (29,397) | (7,042) | ||||
Business Acquisition, Transaction Costs | 5,200 | 4,300 | 36,000 | 5,000 | |||||
Corporate[Member] | Incremental, Non-Recurring Acquisition Costs (Net of Tax) [Member] | |||||||||
Segment Reporting Information | |||||||||
Business Acquisition, Transaction Costs | 4,000 | 2,800 | 24,000 | 3,000 | |||||
Corporate[Member] | Labor (Net Of Tax) [Member] | |||||||||
Segment Reporting Information | |||||||||
Business Acquisition, Transaction Costs | 1,700 | 1,200 | 7,400 | 1,800 | |||||
Consolidation, Eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 0 | 0 | 0 | 0 | |||||
Electric Utilities [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 171,754 | 176,042 | [2] | 493,845 | 504,049 | [2] | |||
Net income (loss) available for common stock | 24,181 | 22,659 | [2] | 62,625 | 57,844 | [2] | |||
Electric Utilities [Member] | Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 2,747 | 2,548 | [2] | 9,413 | 8,481 | [2] | |||
Gas Utilities [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 141,445 | [3] | 75,155 | [2] | 563,879 | [3] | 416,950 | [2] | |
Net income (loss) available for common stock | (2,939) | 652 | [2] | 29,975 | 27,475 | [2] | |||
Gas Utilities [Member] | Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 0 | 0 | [2] | 0 | 0 | [2] | |||
Power Generation [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 1,906 | 2,123 | 5,304 | 5,782 | |||||
Net income (loss) available for common stock | 5,642 | [4] | 9,067 | 19,907 | [4] | 24,761 | |||
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest | 3,800 | 6,400 | |||||||
Power Generation [Member] | Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 21,431 | 21,128 | 63,055 | 62,452 | |||||
Mining [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 9,042 | 8,890 | 20,498 | 26,084 | |||||
Net income (loss) available for common stock | 3,307 | 3,047 | 6,969 | 9,106 | |||||
Mining [Member] | Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 7,778 | 8,076 | 23,651 | 23,541 | |||||
Oil and Gas [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | 9,639 | 9,895 | 25,660 | 33,481 | |||||
Net income (loss) available for common stock | [5] | (8,828) | (39,769) | [6] | (35,277) | (130,079) | [6] | ||
Impairment of Oil and Gas Properties Net of Tax | 7,900 | 36,000 | 33,000 | 113,000 | |||||
Oil and Gas [Member] | Inter-company eliminations [Member] | |||||||||
Segment Reporting Information | |||||||||
Revenue | $ 0 | $ 0 | $ 0 | $ 0 | |||||
[1] | Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 included incremental, non-recurring acquisition costs, net of tax of $4.0 million and $24 million; and $2.8 million and $3.0 million respectively, and after-tax internal labor costs attributable to the acquisition of $1.7 million and $7.4 million; and $1.2 million and $1.8 million respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. | ||||||||
[2] | Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $6.2 million and $31 million, respectively, and Net loss of $1.0 million and Net income of $0.5 million, respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. | ||||||||
[3] | Gas Utility revenue increased for the three and nine months ended September 30, 2016 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016. | ||||||||
[4] | Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.8 million and $6.4 million for the three and nine months ended September 30, 2016. | ||||||||
[5] | Net income (loss) available for common stock for the three and nine months ended September 30, 2016 and September 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $7.9 million and $33 million and $36 million and $113 million, respectively. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. | ||||||||
[6] | Net income (loss) available for common stock for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
Business Segment Information_ S
Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | $ 6,452,136 | $ 4,231,932 | $ 6,452,136 | $ 4,231,932 | $ 4,642,317 | ||||||
Impairment of long-lived assets | 12,293 | 61,875 | 52,286 | 178,395 | |||||||
Corporate[Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | 141,795 | 120,545 | 141,795 | 120,545 | 576,358 | [1] | |||||
Electric Utilities [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | [2] | 2,824,145 | 2,706,654 | [3] | 2,824,145 | 2,706,654 | [3] | 2,720,004 | [3] | ||
Gas Utilities [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | 3,182,852 | [4] | 967,225 | [3] | 3,182,852 | [4] | 967,225 | [3] | 999,778 | [3] | |
Power Generation [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | [2] | 77,570 | 78,666 | 77,570 | 78,666 | 60,864 | |||||
Mining [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | 66,804 | 78,000 | 66,804 | 78,000 | 76,357 | ||||||
Oil and Gas [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | [5] | $ 158,970 | 280,842 | 158,970 | 280,842 | 208,956 | |||||
Impairment of long-lived assets | $ 52,000 | 250,000 | |||||||||
Assets, Total [Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Prior Period Reclassification Adjustment Balance Sheet | $ 136,000 | $ 136,000 | 135,000 | ||||||||
Cash and Cash Equivalents [Member] | Corporate[Member] | |||||||||||
Segment Reporting, Asset Reconciling Item [Line Items] | |||||||||||
Assets | $ 440,000 | ||||||||||
[1] | Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016. | ||||||||||
[2] | The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. | ||||||||||
[3] | Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the nine months ended September 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $136 million, respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and September 30, 2015. | ||||||||||
[4] | Includes the assets acquired in the SourceGas acquisition on February 12, 2016. | ||||||||||
[5] | As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $52 million for the nine months ended September 30, 2016, $250 million for the year ended December 31, 2015, and $178 million for the nine months ended September 30, 2015. See Note 20 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. |
Accounts Receivable_ Accounts57
Accounts Receivable: Accounts Receivable (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | ||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | $ (2,516) | $ (1,741) | $ (1,351) | ||
Accounts receivable, net | 154,617 | 147,486 | 115,502 | ||
Corporate[Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | 0 | 0 | 0 | ||
Accounts receivable, net | 1,659 | 1,025 | 1,566 | ||
Electric Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | (580) | (727) | [1] | (811) | [1] |
Accounts receivable, net | 75,137 | 76,826 | [1] | 74,823 | [1] |
Gas Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | (1,923) | (1,001) | [1] | (527) | [1] |
Accounts receivable, net | 69,716 | 62,199 | [1] | 30,734 | [1] |
Power Generation [Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | 0 | 0 | 0 | ||
Accounts receivable, net | 1,165 | 1,187 | 1,186 | ||
Mining [Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | 0 | 0 | 0 | ||
Accounts receivable, net | 3,612 | 2,760 | 2,684 | ||
Oil and Gas [Member] | |||||
Accounts Receivable [Line Items] | |||||
Allowance for Doubtful Accounts | (13) | (13) | (13) | ||
Accounts receivable, net | 3,328 | 3,489 | 4,509 | ||
Billed Revenues [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 102,581 | 80,484 | 71,644 | ||
Billed Revenues [Member] | Corporate[Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 1,659 | 1,025 | 1,566 | ||
Billed Revenues [Member] | Electric Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 44,747 | 41,679 | [1] | 41,655 | [1] |
Billed Revenues [Member] | Gas Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 48,057 | 30,331 | [1] | 20,031 | [1] |
Billed Revenues [Member] | Power Generation [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 1,165 | 1,187 | 1,186 | ||
Billed Revenues [Member] | Mining [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 3,612 | 2,760 | 2,684 | ||
Billed Revenues [Member] | Oil and Gas [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 3,341 | 3,502 | 4,522 | ||
Unbilled Revenues [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 54,552 | 68,743 | 45,209 | ||
Unbilled Revenues [Member] | Corporate[Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 0 | 0 | 0 | ||
Unbilled Revenues [Member] | Electric Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 30,970 | 35,874 | [1] | 33,979 | [1] |
Unbilled Revenues [Member] | Gas Utilities [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 23,582 | 32,869 | [1] | 11,230 | [1] |
Unbilled Revenues [Member] | Power Generation [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 0 | 0 | 0 | ||
Unbilled Revenues [Member] | Mining [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | 0 | 0 | 0 | ||
Unbilled Revenues [Member] | Oil and Gas [Member] | |||||
Accounts Receivable [Line Items] | |||||
Accounts Receivable, Trade | $ 0 | 0 | 0 | ||
Accounts Receivable, Trade | |||||
Accounts Receivable [Line Items] | |||||
Prior Period Reclassification Adjustment Balance Sheet | $ 6,800 | $ 2,900 | |||
[1] | Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $2.9 million as of December 31, 2015 and September 30, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment. |
Regulatory Accounting_ Regula58
Regulatory Accounting: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | Apr. 29, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | |
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets | $ 284,801 | $ 232,484 | $ 234,299 | ||
Regulatory Liabilities | $ 203,421 | 153,041 | 157,811 | ||
Deferred energy and gas costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 1 year | ||||
Regulatory Liabilities | [1],[2] | $ 15,033 | 7,814 | 9,899 | |
Employee benefit plans | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 12 years | ||||
Regulatory Liabilities | [3],[4] | $ 65,575 | 47,218 | 53,140 | |
Cost of removal | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 44 years | ||||
Regulatory Liabilities | [2] | $ 114,616 | 90,045 | 86,946 | |
Other regulatory liabilities | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 25 years | ||||
Regulatory Liabilities | [3] | $ 8,197 | 7,964 | 7,826 | |
Deferred energy and gas costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 1 year | ||||
Regulatory Assets | [1],[2] | $ 16,525 | 24,751 | 25,354 | |
Deferred gas cost adjustments | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 1 year | ||||
Regulatory Assets | [1],[2] | $ 12,172 | 15,521 | 9,358 | |
Gas price derivatives | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 7 years | ||||
Regulatory Assets | [2] | $ 14,405 | 23,583 | 23,681 | |
AFUDC | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 45 years | ||||
Regulatory Assets | [5] | $ 14,093 | 12,870 | 12,580 | |
Employee benefit plans | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 12 years | ||||
Regulatory Assets | [3],[4] | $ 107,578 | 83,986 | 95,779 | |
Environmental | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets | [2] | $ 1,126 | 1,180 | 1,209 | |
Asset retirement obligations | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 44 years | ||||
Regulatory Assets | [2] | $ 507 | 457 | 675 | |
Loss on reacquired debt | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 30 years | ||||
Regulatory Assets | [2] | $ 15,918 | 3,133 | 3,169 | |
Renewable energy standard adjustment | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 5 years | ||||
Regulatory Assets | [5] | $ 1,694 | 5,068 | 5,102 | |
Flow through accounting | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 35 years | ||||
Regulatory Assets | [3] | $ 33,136 | 29,722 | 28,585 | |
Decommissioning costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 10 years | ||||
Regulatory Assets | [6] | $ 17,271 | 18,310 | 16,353 | |
Gas Supply Contract Termination [Member] | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 5 years | 5 years | |||
Regulatory Assets | $ 30,000 | $ 28,164 | 0 | 0 | |
Other regulatory assets | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Maximum Amortization Period | 15 years | ||||
Regulatory Assets | [2] | $ 22,212 | $ 13,903 | $ 12,454 | |
Black Hills Power [Member] | Decommissioning costs | |||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | |||||
Regulatory Assets | [6] | $ 12,000 | |||
[1] | Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. | ||||
[2] | Recovery of costs, but we are not allowed a rate of return. | ||||
[3] | 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. | ||||
[4] | Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans. | ||||
[5] | In addition to recovery of costs, we are allowed a rate of return. | ||||
[6] | South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs. |
Regulatory Accounting_ Gas Supp
Regulatory Accounting: Gas Supply Contract Termination (Details) - $ / Btu | Apr. 29, 2016 | Sep. 30, 2016 |
Minimum [Member] | ||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | 6 | |
Maximum [Member] | ||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | 8 | |
Gas Supply Contract Termination [Member] | ||
Regulatory Assets Amortization Period, Unclassified | 5 years | 5 years |
Materials, Supplies and Fuel_60
Materials, Supplies and Fuel: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Inventory, Net [Abstract] | |||
Materials and supplies | $ 67,257 | $ 55,726 | $ 53,838 |
Fuel - Electric Utilities | 4,282 | 5,567 | 6,139 |
Natural gas in storage held for distribution | 41,936 | 25,650 | 30,372 |
Total materials, supplies and fuel | $ 113,475 | $ 86,943 | $ 90,349 |
Goodwill & Intangible Assets_61
Goodwill & Intangible Assets: Goodwill (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2016 | Dec. 31, 2015 | ||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | $ 359,759 | ||
Additions | [1] | 940,620 | |
Goodwill, ending balance | 1,300,379 | ||
Goodwill [Member] | |||
Goodwill [Line Items] | |||
Prior Period Reclassification Adjustment Balance Sheet | $ 6,300 | ||
Electric Utilities [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | [2] | 256,850 | |
Additions | 0 | ||
Goodwill, ending balance | [2] | 256,850 | |
Gas Utilities [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | [2] | 94,144 | |
Additions | [1] | 940,620 | |
Goodwill, ending balance | [2] | 1,034,764 | |
Power Generation [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 8,765 | ||
Additions | 0 | ||
Goodwill, ending balance | $ 8,765 | ||
[1] | Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. | ||
[2] | Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details. |
Goodwill & Intangible Assets_ I
Goodwill & Intangible Assets: Intangible Assets (Details) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016USD ($) | ||
Finite-lived Intangible Assets [Roll Forward] | ||
Intangible assets, net, beginning balance | $ 3,380 | |
Intangible assets, net, ending balance | $ 8,944 | |
Source Gas [Member] | ||
Finite-Lived Intangible Assets [Line Items] | ||
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life | 10 years | |
Finite-lived Intangible Assets [Roll Forward] | ||
Additions, net | $ 5,564 | [1] |
[1] | Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10-year estimated useful lives. See Note 2 for more information. |
Asset Retirement Obligations_63
Asset Retirement Obligations: Asset Retirement Obligations (Details) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016USD ($) | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Beginning Balance | $ 44,735 | |
Liabilities Incurred | 0 | |
Liabilities Settled | (829) | |
Accretion Expense | 2,321 | |
Liabilities Acquired | 22,412 | |
Revision of Estimate | 901 | |
Asset Retirement Obligation, Ending Balance | 69,540 | |
Electric Utilities [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Beginning Balance | 4,462 | |
Liabilities Incurred | 0 | |
Liabilities Settled | 0 | |
Accretion Expense | 143 | |
Liabilities Acquired | 0 | |
Revision of Estimate | 11 | |
Asset Retirement Obligation, Ending Balance | 4,616 | |
Gas Utilities [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Beginning Balance | 136 | |
Liabilities Incurred | 0 | |
Liabilities Settled | 0 | |
Accretion Expense | 478 | |
Liabilities Acquired | 22,412 | [1] |
Revision of Estimate | 6,436 | [2] |
Asset Retirement Obligation, Ending Balance | 29,462 | |
Gas Utilities [Member] | Scenario, Previously Reported [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Regulatory Liability | 22,000 | |
Mining [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Beginning Balance | 18,633 | |
Liabilities Incurred | 0 | |
Liabilities Settled | (15) | |
Accretion Expense | 653 | |
Liabilities Acquired | 0 | |
Revision of Estimate | (5,603) | [3] |
Asset Retirement Obligation, Ending Balance | $ 13,668 | |
Percentage Change in Equipment Costs | (33.00%) | |
Oil and Gas [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligation, Beginning Balance | $ 21,504 | |
Liabilities Incurred | 0 | |
Liabilities Settled | (814) | |
Accretion Expense | 1,047 | |
Liabilities Acquired | 0 | |
Revision of Estimate | 57 | |
Asset Retirement Obligation, Ending Balance | $ 21,794 | |
[1] | Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. | |
[2] | The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. | |
[3] | The Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. |
Earnings Per Share_ Earnings 64
Earnings Per Share: Earnings Per Share (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||||
Earnings Per Share [Abstract] | |||||||
Net income (loss) available for common stock | $ 14,131 | $ (9,943) | $ 54,802 | $ (17,935) | |||
Weighted average shares - basic | 52,184 | 44,635 | 51,583 | 44,598 | |||
Dilutive effect of: | |||||||
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities | [1] | 1,414 | 0 | 1,191 | 0 | ||
Equity compensation | 135 | 0 | 119 | 0 | |||
Weighted average shares - diluted | 53,733 | 44,635 | [2] | 52,893 | 44,598 | [2] | |
Securities Excluded From Diluted Earnings Per Share Due To Net Loss | 58,380 | 82,130 | |||||
[1] | Calculated using the treasury stock method. | ||||||
[2] | Due to our net loss for the three and nine months ended September 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 58,380 and 82,130 equity compensation shares were excluded from the computations for the three and nine months ended September 30, 2015, respectively. |
Earnings Per Share_ Anti-diluti
Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Securities Excluded From Diluted Earnings Per Share Due To Net Loss | 58,380 | 82,130 | ||
Anti-dilutive shares | 2 | 121 | 4 | 114 |
Stock Compensation Plan [Member] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Anti-dilutive shares | 2 | 121 | 4 | 114 |
Notes Payable_ Notes Payable (D
Notes Payable: Notes Payable (Details) | Aug. 09, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) |
Revolving Credit Facility [Line Items] | |||||
Balance Outstanding | $ 75,000,000 | $ 76,800,000 | $ 117,900,000 | ||
Revolving Credit Facility [Member] | |||||
Revolving Credit Facility [Line Items] | |||||
Balance Outstanding | 75,000,000 | 76,800,000 | 117,900,000 | ||
Letters of Credit | $ 30,500,000 | $ 33,399,000 | $ 30,600,000 | ||
Current Borrowing Capacity | $ 750,000,000 | $ 500,000,000 | |||
Expiration Date | Aug. 9, 2021 | ||||
Number Of One-Year Extension Options | 2 | ||||
Debt Instrument, Term | 1 year | ||||
Maximum Borrowing Capacity | $ 1,000,000,000 | ||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.175% | ||||
Revolving Credit Facility [Member] | Base Rate [Member] | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 0.125% | ||||
Revolving Credit Facility [Member] | Eurodollar [Member] | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 1.125% | ||||
Revolving Credit Facility [Member] | Letter of Credit [Member] | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 1.125% |
Notes Payable_ Debt covenants (
Notes Payable: Debt covenants (Details) $ in Thousands | Sep. 30, 2016USD ($) | Feb. 12, 2016 | Feb. 11, 2016 | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) |
Long-term Debt, Gross | $ 3,240,037 | $ 1,866,866 | $ 1,567,797 | ||
Revolving Credit Facility [Member] | |||||
Debt instrument, covenant, Leverage Recourse Ratio | 0.7 | ||||
Recourse Leverage Ratio | 68.00% | ||||
Minimum [Member] | |||||
Debt instrument, covenant, Leverage Recourse Ratio | 0.75 | 0.65 | |||
Debt Instrument, Consolidated Debt to Capitalization Ratio | 0.70 | ||||
Maximum [Member] | |||||
Debt instrument, covenant, Leverage Recourse Ratio | 1 | 1 | |||
Debt Instrument, Consolidated Debt to Capitalization Ratio | 1 | ||||
Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member] | |||||
Long-term Debt, Gross | $ 340,000 |
Long-Term Debt And Current Ma68
Long-Term Debt And Current Maturities Of Long-Term Debt: Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Aug. 19, 2016 | Jun. 07, 2016 | Jan. 13, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | |
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 3,240,037 | $ 1,866,866 | $ 1,567,797 | ||||
Long-term Debt, Current Maturities | (5,743) | 0 | 0 | ||||
Deferred Finance Costs, Net | [1] | (22,526) | (13,184) | (14,630) | |||
Long-term Debt, Excluding Current Maturities | 3,211,768 | 1,853,682 | 1,553,167 | ||||
Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Deferred Finance Costs, Net | (2,500) | (1,700) | (1,900) | ||||
Electric Utilities [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 544,759 | 544,756 | 544,756 | ||||
Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.43% | ||||||
Long-term Debt, Gross | $ 85,000 | 85,000 | 85,000 | ||||
Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.53% | ||||||
Long-term Debt, Gross | $ 75,000 | 75,000 | 75,000 | ||||
Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 7.23% | ||||||
Long-term Debt, Gross | $ 75,000 | 75,000 | 75,000 | ||||
Electric Utilities [Member] | First Mortgage Bonds Due 2039 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.13% | ||||||
Long-term Debt, Gross | $ 180,000 | 180,000 | 180,000 | ||||
Debt Instrument, Unamortized Discount | $ (96) | (99) | (99) | ||||
Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 6.67% | ||||||
Long-term Debt, Gross | $ 110,000 | 110,000 | 110,000 | ||||
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | [2] | 0.86% | |||||
Long-term Debt, Gross | [2] | $ 7,000 | 7,000 | 7,000 | |||
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | [2] | 0.86% | |||||
Long-term Debt, Gross | [2] | $ 10,000 | 10,000 | 10,000 | |||
Electric Utilities [Member] | Bonds Due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | [2] | 1.01% | |||||
Long-term Debt, Gross | [2] | $ 2,855 | 2,855 | 2,855 | |||
Corporate[Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | $ 2,695,278 | 1,322,110 | 1,023,041 | ||||
Corporate[Member] | Remarketable Junior Subordinated Notes Due 2028 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.50% | ||||||
Long-term Debt, Gross | $ 299,000 | 299,000 | 0 | ||||
Corporate[Member] | Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.95% | 3.95% | |||||
Long-term Debt, Gross | $ 300,000 | $ 300,000 | 0 | 0 | |||
Debt Instrument, Unamortized Discount | $ (842) | 0 | 0 | ||||
Corporate[Member] | Senior Unsecured Notes Due 2023 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.25% | ||||||
Long-term Debt, Gross | $ 525,000 | 525,000 | 525,000 | ||||
Debt Instrument, Unamortized Discount | $ (1,685) | (1,890) | (1,959) | ||||
Corporate[Member] | Senior Unsecured Notes Due 2020 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.88% | ||||||
Long-term Debt, Gross | $ 200,000 | 200,000 | 200,000 | ||||
Corporate[Member] | Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.50% | 2.50% | |||||
Long-term Debt, Gross | $ 250,000 | $ 250,000 | 0 | 0 | |||
Debt Instrument, Unamortized Discount | $ (205) | 0 | 0 | ||||
Corporate[Member] | Senior Unsecured Notes Due 2027 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.15% | 3.15% | |||||
Long-term Debt, Gross | $ 400,000 | $ 400,000 | 0 | 0 | |||
Debt Instrument, Unamortized Discount | $ (202) | 0 | 0 | ||||
Corporate[Member] | Senior Unsecured Notes Due 2046 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 4.20% | 4.20% | |||||
Long-term Debt, Gross | $ 300,000 | $ 300,000 | 0 | 0 | |||
Debt Instrument, Unamortized Discount | $ (1,630) | 0 | 0 | ||||
Corporate[Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.32% | 2.32% | |||||
Long-term Debt, Gross | $ 25,842 | $ 29,000 | 0 | 0 | |||
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due August 2019 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | [3] | 1.46% | |||||
Long-term Debt, Gross | [3] | $ 400,000 | 0 | 0 | |||
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due April 2017 [Member] | Black Hills Corporation [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt, Gross | [3] | $ 0 | $ 300,000 | $ 300,000 | |||
[1] | Includes deferred financing costs associated with our Revolving Credit Facility of $2.5 million, $1.7 million and $1.9 million as of September 30, 2016, December 31, 2015 and September 30, 2015, respectively. | ||||||
[2] | Variable interest rate. | ||||||
[3] | Variable interest rate, based on LIBOR plus a spread. |
Long-Term Debt And Current Ma69
Long-Term Debt And Current Maturities Of Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) $ in Thousands | Sep. 30, 2016USD ($) |
Long-term Debt, Unclassified [Abstract] | |
2,016 | $ 1,436 |
2,017 | 5,743 |
2,018 | 5,743 |
2,019 | 655,743 |
2,020 | 205,742 |
Thereafter | $ 2,370,290 |
Long-Term Debt And Current Ma70
Long-Term Debt And Current Maturities Of Long-Term Debt: Current Maturities of Long-Term Debt (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2016 | Jun. 07, 2016 | ||
Debt Instrument [Line Items] | |||
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months | $ 5,743 | ||
Black Hills Corporation [Member] | Corporate[Member] | Corporate Term Loan Due June 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months | [1] | $ 5,743 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.32% | 2.32% | |
Debt Instrument, Periodic Payment, Principal | $ 1,400 | ||
Debt Instrument, Frequency of Periodic Payment | quarterly | ||
[1] | Principal payments of $1.4 million are due quarterly. |
Long-Term Debt And Current Ma71
Long-Term Debt And Current Maturities Of Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands | Aug. 19, 2016 | Aug. 09, 2016 | Jun. 07, 2016 | Jan. 13, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Feb. 12, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 3,240,037 | $ 1,567,797 | $ 1,866,866 | ||||||
Gain (Loss) on Sale of Derivatives | 28,820 | 0 | |||||||
Long-term debt - issuances | $ 546,000 | 1,767,608 | 300,000 | ||||||
Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Proceeds from Issuance of Senior Long-term Debt | $ 700,000 | 550,000 | |||||||
Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | 340,000 | ||||||||
Source Gas [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Extinguishment of Debt, Amount | 760,000 | ||||||||
Source Gas [Member] | Senior Unsecured Notes Due 2017 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.90% | 5.90% | |||||||
Extinguishment of Debt, Amount | $ 325,000 | ||||||||
Source Gas [Member] | Senior Secured Notes due 2019 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.98% | 3.98% | |||||||
Extinguishment of Debt, Amount | $ 95,000 | ||||||||
Source Gas [Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Extinguishment of Debt, Amount | 100,000 | $ 240,000 | |||||||
Corporate[Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | 2,695,278 | 1,023,041 | 1,322,110 | ||||||
Corporate[Member] | Senior Unsecured Notes Due 2027 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 400,000 | $ 400,000 | 0 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.15% | 3.15% | |||||||
Debt Instrument, Term | 10 years | ||||||||
Corporate[Member] | Senior Unsecured Notes Due 2046 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 300,000 | $ 300,000 | 0 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.20% | 4.20% | |||||||
Debt Instrument, Term | 30 years | ||||||||
Corporate[Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 29,000 | $ 25,842 | 0 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 2.32% | 2.32% | |||||||
Debt Instrument, Frequency of Periodic Payment | quarterly | ||||||||
Debt Instrument, Periodic Payment | $ 1,600 | ||||||||
Corporate[Member] | Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 300,000 | $ 300,000 | 0 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.95% | 3.95% | |||||||
Debt Instrument, Term | 10 years | ||||||||
Corporate[Member] | Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | $ 250,000 | $ 250,000 | 0 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 2.50% | 2.50% | |||||||
Debt Instrument, Term | 3 years | ||||||||
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due August 2019 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | [1] | $ 400,000 | 0 | 0 | |||||
Extinguishment of Debt, Amount | $ 100,000 | ||||||||
Proceeds from Issuance of Other Long-term Debt | [1] | $ 500,000 | |||||||
Debt Instrument, Term | 3 years | ||||||||
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due April 2017 [Member] | Black Hills Corporation [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term Debt, Gross | [1] | 0 | $ 300,000 | $ 300,000 | |||||
Extinguishment of Debt, Amount | $ 260,000 | ||||||||
Interest Rate Swap [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Gain (Loss) on Sale of Derivatives | (29,000) | (29,000) | |||||||
Notional Amount | $ 400,000 | $ 400,000 | |||||||
[1] | Variable interest rate, based on LIBOR plus a spread. |
Long-Term Debt And Current Ma72
Long-Term Debt And Current Maturities Of Long-Term Debt: Assumption of Black Hills Holdings LTD (Details) - Source Gas [Member] - USD ($) $ in Thousands | Aug. 19, 2016 | Aug. 09, 2016 | Sep. 30, 2016 | Feb. 12, 2016 | |
Debt Instrument [Line Items] | |||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | $ 760,000 | ||||
Extinguishment of Debt, Amount | $ 760,000 | ||||
Senior Unsecured Notes Due 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | [1] | $ 325,000 | |||
Debt Instrument, Interest Rate, Stated Percentage | 5.90% | 5.90% | |||
Extinguishment of Debt, Amount | $ 325,000 | ||||
Senior Secured Notes due 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | $ 95,000 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 3.98% | 3.98% | |||
Extinguishment of Debt, Amount | $ 95,000 | ||||
Black Hills Corporation [Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | [1] | $ 340,000 | |||
Extinguishment of Debt, Amount | $ 100,000 | $ 240,000 | |||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | [1] | 0.875% | |||
[1] | Variable interest rate, based on LIBOR plus a spread. |
Equity_ Stockholders Equity Rec
Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Total Stockholders' Equity, beginning balance | $ 1,465,867 | $ 1,465,867 | ||||||
Noncontrolling Interest, beginning balance | 0 | 0 | ||||||
Total Equity, beginning balance | 1,465,867 | $ 1,353,884 | 1,465,867 | $ 1,353,884 | ||||
Net income (loss) available for common stock | $ 14,131 | $ (9,943) | 54,802 | (17,935) | ||||
Net Income (Loss) Attributable to Noncontrolling Interest | (3,753) | 0 | (6,415) | 0 | ||||
Net Income (Loss) Including Portion Attributable to Noncontrolling Interest (Excluding Income Loss Attributable to Redeemable Noncontrolling Interest) | 61,204 | (17,935) | ||||||
Other comprehensive income (loss) | (1,187) | $ (10,939) | (11,770) | 2,248 | $ (2,805) | 990 | (23,896) | 433 |
Dividends on common stock | (65,247) | (54,450) | ||||||
Share-based compensation | 3,822 | 2,998 | ||||||
Issuance of common stock | 105,238 | 0 | ||||||
Dividend reinvestment and stock purchase plan | 2,242 | 2,298 | ||||||
Other stock transactions | (24) | (16) | ||||||
Distribution to noncontrolling interest | (4,516) | |||||||
Total Stockholders' Equity, ending balance | 1,604,642 | 1,287,212 | 1,604,642 | 1,287,212 | ||||
Sale of noncontrolling interest | 177,334 | |||||||
Noncontrolling Interest, ending balance | 117,382 | 0 | 117,382 | 0 | ||||
Total Equity, ending balance | 1,722,024 | 1,287,212 | 1,722,024 | 1,287,212 | ||||
Parent [Member] | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Total Stockholders' Equity, beginning balance | 1,465,867 | 1,353,884 | 1,465,867 | 1,353,884 | ||||
Net income (loss) available for common stock | 54,802 | (17,935) | ||||||
Other comprehensive income (loss) | (23,896) | 433 | ||||||
Dividends on common stock | (65,247) | (54,450) | ||||||
Share-based compensation | 3,822 | 2,998 | ||||||
Issuance of common stock | 105,238 | 0 | ||||||
Dividend reinvestment and stock purchase plan | 2,242 | 2,298 | ||||||
Other stock transactions | (24) | (16) | ||||||
Distribution to noncontrolling interest | 0 | |||||||
Total Stockholders' Equity, ending balance | 1,604,642 | 1,287,212 | 1,604,642 | 1,287,212 | ||||
Sale of noncontrolling interest | 61,838 | |||||||
Noncontrolling Interest [Member] | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Noncontrolling Interest, beginning balance | $ 0 | $ 0 | 0 | 0 | ||||
Net Income (Loss) Attributable to Noncontrolling Interest | 6,402 | 0 | ||||||
Other comprehensive income (loss) | 0 | 0 | ||||||
Dividends on common stock | 0 | 0 | ||||||
Share-based compensation | 0 | 0 | ||||||
Issuance of common stock | 0 | 0 | ||||||
Dividend reinvestment and stock purchase plan | 0 | 0 | ||||||
Other stock transactions | 0 | 0 | ||||||
Distribution to noncontrolling interest | (4,516) | |||||||
Sale of noncontrolling interest | 115,496 | |||||||
Noncontrolling Interest, ending balance | $ 117,382 | $ 0 | $ 117,382 | $ 0 |
Equity_ At-the-Market Equity Of
Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions | Oct. 05, 2016 | Sep. 30, 2016 | Sep. 30, 2016 | Mar. 18, 2016 |
At The Market Equity Offering Program Authorized Aggregate Value | $ 200 | |||
Payments of Stock Issuance Costs | $ 0.5 | $ 1.1 | ||
Common Stock [Member] | ||||
At The Market Equity Offering Program Shares Issued | 819,442 | 1,750,091 | ||
At the Market Equity Program - Proceeds From Sale of Stock | $ 49 | $ 106 | ||
Subsequent Event [Member] | Common Stock [Member] | ||||
At The Market Equity Offering Program Shares Issued | 38,781 | |||
At the Market Equity Program - Proceeds From Sale of Stock | $ 2.4 |
Equity_ Variable Interest Entit
Equity: Variable Interest Entities (Details) - USD ($) $ in Thousands | Apr. 14, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 |
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||
Sale of noncontrolling interest | $ 216,370 | $ 0 | ||
Current assets | 418,171 | 402,282 | $ 822,151 | |
Property, plant and equipment of variable interest entities, net | 6,306,119 | 4,882,420 | 4,976,778 | |
Current liabilities | 480,820 | 448,689 | 422,029 | |
Variable Interest Entity, Primary Beneficiary [Member] | ||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||
Sale of noncontrolling interest | $ 216,000 | |||
Current assets | 14,191 | 0 | 0 | |
Property, plant and equipment of variable interest entities, net | 220,818 | 0 | 0 | |
Current liabilities | $ 3,353 | $ 0 | $ 0 |
Risk Management Activities_ Oil
Risk Management Activities: Oil and Gas (Details) - Oil and Gas [Member] $ in Millions | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016USD ($)MMBTUbbl | Sep. 30, 2015MMBTUbbl | Dec. 31, 2015MMBTUbbl | ||
Derivative [Line Items] | ||||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $ | $ 2.4 | |||
Crude Oil [Member] | Swaps and Options [Member] | ||||
Derivative [Line Items] | ||||
Notional amount - commodities | [1] | 159,000 | 258,000 | 198,000 |
Maximum Term Hedged in Cash Flow Hedge | [2] | 27 months | 27 months | 24 months |
Crude Oil [Member] | Options Held [Member] | ||||
Derivative [Line Items] | ||||
Notional amount - commodities | [1] | 36,000 | ||
Maximum Term Hedged in Cash Flow Hedge | [2] | 15 months | ||
Natural Gas [Member] | Swap [Member] | ||||
Derivative [Line Items] | ||||
Notional amount - commodities | MMBTU | [1] | 1,625,000 | 5,392,500 | 4,392,500 |
Maximum Term Hedged in Cash Flow Hedge | [2] | 15 months | 27 months | 24 months |
[1] | Crude oil futures and call options in Bbls, natural gas in MMBtus. | |||
[2] | Term reflects the maximum forward period hedged. |
Risk Management Activities_ Uti
Risk Management Activities: Utilities (Details) - Purchase Contract [Member] - Natural Gas, Distribution [Member] - MMBTU | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |||
Future [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 17,740,000 | 17,180,000 | 20,580,000 | ||
Maximum Term | [1] | 51 months | 63 months | 60 months | |
Commodity Option [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 6,540,000 | 6,300,000 | 2,620,000 | ||
Maximum Term | [1] | 17 months | 6 months | 3 months | |
Basis Swap [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 13,650,000 | [2] | 12,980,000 | 18,150,000 | |
Maximum Term | [1] | 51 months | 51 months | 60 months | |
Fixed for Float Swaps Purchased [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 4,749,000 | [3] | 0 | 0 | |
Maximum Term | [1] | 20 months | 0 months | 0 months | |
Collar Options not included [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 2,306,000 | ||||
Natural Gas Physical Purchases [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | 15,666,202 | 0 | 0 | ||
Maximum Term | [1] | 13 months | 0 months | 0 months | |
Cash Flow Hedging [Member] | Fixed for Float Swaps Purchased [Member] | |||||
Derivative [Line Items] | |||||
Notional amount - commodities | [3] | 2,640,000 | |||
[1] | Term reflects the maximum forward period hedged. | ||||
[2] | Volumes purchased as of September 30, 2016 is net of 2,306,000 MMBtus of collar options (call purchase and put sale) transactions. | ||||
[3] | 2,640,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased. |
Risk Management Activities_ Fin
Risk Management Activities: Financing Activities (Details) - USD ($) $ in Thousands | Aug. 19, 2016 | Aug. 09, 2016 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Derivative [Line Items] | ||||||
Gain (Loss) on Sale of Derivatives | $ 28,820 | $ 0 | ||||
Long-term Debt, Gross | 3,240,037 | 1,567,797 | $ 1,866,866 | |||
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion | 28,000 | |||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 1,000 | |||||
Derivative assets, non-current | 183 | 0 | 3,441 | |||
Derivative liabilities, current | 1,941 | 3,312 | 2,835 | |||
Derivative liabilities, non-current | 317 | 722 | 156 | |||
Revolving Credit Facility [Member] | ||||||
Derivative [Line Items] | ||||||
Debt Instrument, Term | 1 year | |||||
Corporate, Non-Segment [Member] | Black Hills Corporation [Member] | ||||||
Derivative [Line Items] | ||||||
Long-term Debt, Gross | 2,695,278 | 1,023,041 | 1,322,110 | |||
Corporate, Non-Segment [Member] | Black Hills Corporation [Member] | Senior Unsecured Notes Due 2027 [Member] | ||||||
Derivative [Line Items] | ||||||
Long-term Debt, Gross | $ 400,000 | 400,000 | 0 | 0 | ||
Debt Instrument, Term | 10 years | |||||
Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Notional Amount | $ 400,000 | 400,000 | ||||
Gain (Loss) on Sale of Derivatives | $ (29,000) | (29,000) | ||||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ||||||
Derivative [Line Items] | ||||||
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net | (3,400) | |||||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap One [Member] | ||||||
Derivative [Line Items] | ||||||
Notional Amount | [1] | $ 250,000 | ||||
Weighted average fixed interest rate | 2.29% | |||||
Maximum Term | 1 year 4 months | |||||
Derivative assets, non-current | $ 3,441 | |||||
Derivative liabilities, current | 0 | |||||
Derivative liabilities, non-current | 0 | |||||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Revolving Credit Facility [Member] | ||||||
Derivative [Line Items] | ||||||
Notional Amount | [2] | $ 75,000 | $ 75,000 | $ 75,000 | ||
Weighted average fixed interest rate | 4.97% | 4.97% | 4.97% | |||
Maximum Term | 4 months | 1 year 4 months | 1 year | |||
Derivative assets, non-current | $ 0 | $ 0 | $ 0 | |||
Derivative liabilities, current | 654 | 3,312 | 2,835 | |||
Derivative liabilities, non-current | $ 0 | $ 722 | $ 156 | |||
[1] | These swaps were settled in August 2016 in conjunction with the refinancing of acquired SourceGas debt. | |||||
[2] | These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings. |
Risk Management Activities_ Hed
Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | $ 1,000 | |||
Cash Flow Hedging [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | $ (291) | $ 4,382 | (31,222) | $ 4,126 |
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | (1,489) | (1,506) | (6,587) | (5,998) |
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 0 | 0 | 0 | 0 |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | (465) | (898) | (31,130) | (2,674) |
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 0 | 0 | 0 | 0 |
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | 840 | 1,603 | 2,530 | 4,709 |
Cash Flow Hedging [Member] | Commodity Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | 5,280 | (312) | 6,800 | |
Cash Flow Hedging [Member] | Commodity Contract [Member] | Revenue [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | 727 | |||
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | (2,201) | (3,109) | (9,140) | (10,707) |
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 0 | $ 0 | 0 | $ 0 |
Cash Flow Hedging [Member] | Commodity Contract [Member] | Cost of Sales [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | (553) | 220 | ||
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion) | (128) | 23 | ||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | $ 0 | $ 0 |
Fair Value Measurements_ Fair80
Fair Value Measurements: Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract] | |||
Assets-Transfers out of level 1 to 2 | $ 0 | $ 0 | $ 0 |
Assets -Transfers out of level 2 to 1 | 0 | 0 | 0 |
Liabilities -Transfers out of level 1 to 2 | 0 | 0 | 0 |
Liabilities -Transfers out of level 2 to 1 | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (3,647) | (12,937) | (14,387) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (15,231) | (25,141) | (24,912) |
Fair Value, Measurements, Recurring [Member] | Utilities Group [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | (3,647) | (2,293) | (3,123) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (15,231) | (24,585) | (24,445) |
Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | 0 | (10,644) | (11,264) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | (556) | (467) |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 0 | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Utilities Group [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 8,212 | 16,378 | 14,387 |
Derivative Liabilities, Total | 17,489 | 28,132 | 28,946 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Utilities Group [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 5,330 | 2,293 | 3,123 |
Derivative Liabilities, Fair Value Disclosure | 16,130 | 24,585 | 24,445 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 2,882 | 10,644 | 11,264 |
Derivative Liabilities, Fair Value Disclosure | 705 | 556 | 467 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 0 | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Utilities Group [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | 0 | 0 |
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 3,441 | 0 |
Derivative Liabilities, Fair Value Disclosure | 654 | 2,991 | 4,034 |
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 0 | 0 | 0 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 4,565 | 3,441 | 0 |
Derivative Liabilities, Total | 2,258 | 2,991 | 4,034 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 1,683 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 899 | 0 | 0 |
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 2,882 | 0 | 0 |
Derivative Liabilities, Fair Value Disclosure | 705 | 0 | 0 |
Estimate of Fair Value Measurement [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 0 | 3,441 | 0 |
Derivative Liabilities, Fair Value Disclosure | $ 654 | $ 2,991 | $ 4,034 |
Fair Value Measurements_ Balanc
Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Designated as Hedging Instrument [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Net | $ 2,985 | $ 14,085 | $ 11,264 |
Derivative Liability, Fair Value, Net | 1,389 | 3,547 | 4,501 |
Not Designated as Hedging Instrument [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Net | 1,580 | 0 | 0 |
Derivative Liability, Fair Value, Net | 869 | 22,292 | 21,322 |
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 2,919 | 9,981 | 9,181 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | 0 |
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 66 | 663 | 2,083 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | 0 |
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 479 | 465 | 375 |
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 256 | 91 | 92 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 1,463 | 0 | 0 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | 0 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 117 | 0 | 0 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | 0 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 808 | 9,586 | 8,427 |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 61 | 12,706 | 12,895 |
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 0 | 3,441 | |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | |
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 654 | 2,835 | 3,312 |
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member] | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | $ 0 | $ 156 | $ 722 |
Fair Value of Financial Instr82
Fair Value of Financial Instruments: Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Dec. 31, 2014 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Cash and cash equivalents | $ 62,964 | $ 456,535 | $ 38,841 | $ 21,218 | |
Restricted cash and equivalents | 2,140 | 1,697 | 2,462 | ||
Notes payable | 75,000 | 76,800 | 117,900 | ||
Carrying Amount [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Cash and cash equivalents | 62,964 | 456,535 | 38,841 | ||
Restricted cash and equivalents | 2,140 | 1,697 | 2,462 | ||
Notes payable | 75,000 | 76,800 | 117,900 | ||
Long-term debt, including current maturities | 3,217,511 | 1,853,682 | 1,553,167 | ||
Fair Value [Member] | |||||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||||
Cash and cash equivalents, Fair Value | [1] | 62,964 | 456,535 | 38,841 | |
Restricted Cash Fair Value Disclosure | [1] | 2,140 | 1,697 | 2,462 | |
Notes payable, Fair Value | [1] | 75,000 | 76,800 | 117,900 | |
Long-term debt, including current maturities, Fair Value | [2] | $ 3,525,362 | $ 1,992,274 | $ 1,718,964 | |
[1] | Carrying value approximates fair value due to either the 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. | ||||
[2] | 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. |
Other Comprehensive Income (L83
Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Interest expense | $ 37,306 | $ 22,378 | $ 103,989 | $ 61,833 |
Revenue | (333,786) | (272,105) | (1,109,186) | (986,346) |
Fuel, purchased power and cost of natural gas sold | (80,194) | (71,627) | (336,539) | (350,778) |
Operations and maintenance | 115,103 | 89,830 | 334,706 | 273,374 |
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 24,528 | (21,978) | 72,422 | (27,061) |
Income tax benefit (expense) | (6,644) | 12,035 | (11,205) | 14,640 |
Reclassification adjustments related to cash flow hedges, net of tax | 14,131 | (9,943) | 54,802 | (17,935) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | (1,489) | (1,506) | (6,587) | (5,998) |
Income tax benefit (expense) | 566 | 558 | 2,450 | 2,548 |
Reclassification adjustments related to cash flow hedges, net of tax | (923) | (948) | (4,137) | (3,450) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Interest expense | 840 | 1,603 | 2,530 | 4,709 |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Commodity Contract [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Revenue | (2,201) | (3,109) | (9,140) | (10,707) |
Fuel, purchased power and cost of natural gas sold | (128) | 0 | 23 | 0 |
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Operations and maintenance | (55) | (55) | (165) | (166) |
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Operations and maintenance | 494 | 706 | 1,482 | 2,116 |
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 439 | 651 | 1,317 | 1,950 |
Income tax benefit (expense) | (152) | (228) | (459) | (684) |
Reclassification adjustments related to cash flow hedges, net of tax | $ 287 | $ 423 | $ 858 | $ 1,266 |
Other Comprehensive Income (L84
Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | $ (31,764) | $ (20,825) | $ (9,055) | $ (16,859) | $ (14,054) | $ (15,044) | $ (9,055) | $ (15,044) |
Other Comprehensive Income (Loss), Net of Tax | (1,187) | (10,939) | (11,770) | 2,248 | (2,805) | 990 | (23,896) | 433 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (32,951) | (31,764) | (20,825) | (14,611) | (16,859) | (14,054) | (32,951) | (14,611) |
Accumulated Defined Benefit Plans Adjustment [Member] | ||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (15,209) | (15,494) | (15,780) | (19,320) | (19,742) | (20,137) | (15,780) | (20,137) |
Other Comprehensive Income (Loss), Net of Tax | 287 | 285 | 286 | 423 | 422 | 395 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (14,922) | (15,209) | (15,494) | (18,897) | (19,320) | (19,742) | (14,922) | (18,897) |
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (18,526) | (10,877) | 294 | (3,077) | (3,580) | (3,912) | 294 | (3,912) |
Other Comprehensive Income (Loss), Net of Tax | 244 | (7,649) | (11,171) | 457 | 503 | 332 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | (18,282) | (18,526) | (10,877) | (2,620) | (3,077) | (3,580) | (18,282) | (2,620) |
Commodity Contract [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | ||||||||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||||||||
Accumulated Other Comprehensive Income (Loss), Net of Tax | 1,971 | 5,546 | 6,431 | 5,538 | 9,268 | 9,005 | 6,431 | 9,005 |
Other Comprehensive Income (Loss), Net of Tax | (1,718) | (3,575) | (885) | 1,368 | (3,730) | 263 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax | $ 253 | $ 1,971 | $ 5,546 | $ 6,906 | $ 5,538 | $ 9,268 | $ 253 | $ 6,906 |
Supplemental Disclosure of Ca85
Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Non-cash Investing and Financing Activities from Continuing Operations [Abstract] | ||
Property, plant and equipment acquired with accrued liabilities | $ 44,140 | $ 52,314 |
Non-cash Revision to Capitalized Asset Retirement Costs | (2,285) | 0 |
Supplemental Cash Flow Elements [Abstract] | ||
Interest (net of amounts capitalized) | (82,639) | (49,797) |
Income taxes, net | $ (1,168) | $ (1,202) |
Employee Benefit Plans_ Emplo86
Employee Benefit Plans: Employee Benefit Plans (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Feb. 12, 2016 | |
Defined Benefit Pension Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Interest cost | $ 2,800 | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | |||||
Service cost | $ 2,078 | $ 1,494 | 6,234 | $ 4,482 | |
Interest Cost | 3,936 | 3,880 | 11,808 | 11,640 | |
Expected return on plan assets | (5,766) | (4,867) | (17,297) | (14,601) | |
Prior service cost (benefit) | 15 | 15 | 45 | 45 | |
Net loss (gain) | 1,793 | 2,759 | 5,379 | 8,277 | |
Net periodic benefit cost | 2,056 | 3,281 | 6,169 | 9,843 | |
Pension and Other Postretirement Benefit Contributions [Abstract] | |||||
Contributions by Employer | 4,000 | 14,200 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 0 | ||||
Estimated Future Employer Contributions in Next Fiscal Year | 10,200 | ||||
Other Pension Plan, Postretirement or Supplemental Plans [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Interest cost | 300 | ||||
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | |||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 623 | (84) | 1,530 | 799 | |
Interest Cost | 314 | 364 | 943 | 1,092 | |
Prior service cost (benefit) | 1 | 1 | 2 | 3 | |
Net loss (gain) | 207 | 270 | 621 | 810 | |
Net periodic benefit cost | 1,145 | 551 | 3,096 | 2,704 | |
Pension and Other Postretirement Benefit Contributions [Abstract] | |||||
Contributions by Employer | 392 | 1,176 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 392 | ||||
Estimated Future Employer Contributions in Next Fiscal Year | 1,627 | ||||
Other Postretirement Benefit Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Interest cost | 400 | ||||
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | |||||
Service cost | 467 | 464 | 1,401 | 1,392 | |
Interest Cost | 485 | 450 | 1,455 | 1,350 | |
Expected return on plan assets | (70) | (33) | (210) | (99) | |
Prior service cost (benefit) | (107) | (107) | (321) | (321) | |
Net loss (gain) | 84 | 102 | 252 | 306 | |
Net periodic benefit cost | 859 | $ 876 | 2,577 | $ 2,628 | |
Pension and Other Postretirement Benefit Contributions [Abstract] | |||||
Contributions by Employer | $ 1,192 | 3,576 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 1,192 | ||||
Estimated Future Employer Contributions in Next Fiscal Year | $ 4,744 | ||||
Source Gas [Member] | Defined Benefit Pension Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Funded Status of Plan | $ 22,187 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.69% | 3.69% | |||
Source Gas [Member] | Other Postretirement Benefit Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Funded Status of Plan | $ 11,751 | ||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.319% | 3.319% | |||
Scenario, Adjustment [Member] | Defined Benefit Pension Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate (Service Costs) | 4.749% | 4.749% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.827% | 3.827% | |||
Scenario, Adjustment [Member] | Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate (Service Costs) | 4.88% | 4.88% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.817% | 3.817% | |||
Scenario, Adjustment [Member] | Other Postretirement Benefit Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate (Service Costs) | 4.372% | 4.372% | |||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 3.284% | 3.284% | |||
Scenario, Previously Reported [Member] | Defined Benefit Pension Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.575% | 4.575% | |||
Scenario, Previously Reported [Member] | Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.50% | 4.50% | |||
Scenario, Previously Reported [Member] | Other Postretirement Benefit Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.165% | 4.165% |
Commitments and Contingencies87
Commitments and Contingencies: Supply Commitments (Details) - Source Gas [Member] $ in Thousands | Sep. 30, 2016USD ($) |
2,016 | $ 10,476 |
2,017 | 33,324 |
2,018 | 36,906 |
2,019 | 32,576 |
2,020 | 32,260 |
Thereafter | 152,891 |
Total | 298,433 |
Facilities and equipment [Member] | |
2,016 | 758 |
2,017 | 2,236 |
2,018 | 2,230 |
2,019 | 1,698 |
2,020 | 1,382 |
Thereafter | 3,337 |
Total | 11,641 |
Pipeline capacity obligations [Member] | |
2,016 | 9,718 |
2,017 | 31,088 |
2,018 | 34,676 |
2,019 | 30,878 |
2,020 | 30,878 |
Thereafter | 149,554 |
Total | $ 286,792 |
Commitments and Contingencies88
Commitments and Contingencies: Long-term Purchase Commitment (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Refundable Gas Costs | $ 1.6 |
Colorado Interstate Gas [Member] | Public Utilities, Inventory, Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,016 | 1,355 |
2,017 | 6,684 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
Total | 8,039 |
Panhandle Eastern Pipeline [Member] | Public Utilities, Inventory, Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,016 | 239 |
2,017 | 0 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
Total | 239 |
Northwest Wyoming Pool [Member] | Public Utilities, Inventory, Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,016 | 488 |
2,017 | 1,208 |
2,018 | 1,208 |
2,019 | 720 |
2,020 | 0 |
Total | 3,624 |
El Paso San Juan [Member] | Public Utilities, Inventory, Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
2,016 | 98 |
2,017 | 270 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
Total | 368 |
Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
Natural Gas Purchases | $ 6.2 |
Commitments and Contingencies89
Commitments and Contingencies: Build Transfer Agreement (Details) - Peak View Wind Project [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Sep. 30, 2016 | |
Long-term Purchase Commitment, Amount | $ 109 | |
Electric Utilities [Member] | Performance Guarantee [Member] | ||
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 24 |
Commitments and Contingencies90
Commitments and Contingencies: Commitments and Contingencies - Dividend Restrictions (Details) $ in Millions | Sep. 30, 2016USD ($) |
Utilities Group [Member] | |
Related Party Transaction [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 257 |
Impairment of Assets_ Impairmen
Impairment of Assets: Impairment of Long-lived assets (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2016$ / bbl$ / MMcf | Sep. 30, 2015$ / bbl$ / MMcf | |
Impairment of Oil and Gas Properties | $ 52,286 | $ 183,565 | ||||
Oil and Gas [Member] | ||||||
Impairment of Oil and Gas Properties | $ 12,000 | $ 62,000 | $ 38,000 | $ 178,000 | ||
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.28 | 3.06 | ||||
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 1.03 | 1.72 | ||||
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 41.68 | 59.21 | ||||
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 35.88 | 52.82 | ||||
Oil and Gas [Member] | Assets Not Expected To Be Utilized In Cost Of Service Gas Program [Member] | ||||||
Impairment of Oil and Gas Properties | $ 14,000 |
Impairment of Assets_ Equity In
Impairment of Assets: Equity Investments In Unconsolidated Subsidiaries (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Equity Method Investment, Other than Temporary Impairment | $ 0 | $ 0 | $ 0 | $ 5,170 |
Willow Creek / Lodge Creek Pipeline And Gathering System [Member] | Oil and Gas [Member] | ||||
Equity Method Investment, Ownership Percentage | 25.00% | 25.00% | ||
Equity Method Investment, Other than Temporary Impairment | $ 5,200 |
Income Taxes_ Income Taxes (Det
Income Taxes: Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |||||
Income Tax Disclosure [Abstract] | ||||||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||||||
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | 35.00% | ||||
State income tax (net of federal tax effect) | (4.00%) | [1] | 4.70% | 1.70% | 6.70% | |||
Percentage depletion in excess of cost | [2] | (2.30%) | 2.00% | (9.70%) | 4.50% | |||
Accounting for uncertain tax positions adjustment | [3] | (2.40%) | (1.20%) | (7.70%) | (4.70%) | |||
Noncontrolling interest | (3.70%) | [4] | 0.00% | (2.50%) | 0.00% | |||
Transaction costs | 1.40% | 0.00% | ||||||
Flow-through adjustments | (2.20%) | 2.40% | (1.90%) | 4.70% | ||||
Inter-period tax allocation | 7.20% | 11.20% | 0.10% | 0.00% | ||||
Effective Income Tax Rate Reconciliation Allowance For Other Funds Used During Construction, Equity | (0.60%) | 0.00% | ||||||
Other tax differences | 0.10% | 0.70% | (0.90%) | (1.30%) | ||||
Effective Tax Rate | 27.10% | 54.80% | [5] | 15.50% | 44.90% | [5] | ||
IRS Settlement [Abstract] | ||||||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | $ 35 | |||||||
Income Tax Examination, Increase (Decrease) In Accrued Interest | $ 5.1 | 5.1 | ||||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 8 | $ 8 | ||||||
[1] | The state income tax benefit is primarily attributable to favorable flow-through adjustments. | |||||||
[2] | The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. | |||||||
[3] | The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. | |||||||
[4] | The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016. | |||||||
[5] | The tax rate for the three months ended September 30, 2015 represents a tax benefit due to the net loss for the period. |
Accrued Liabilities_ Accrued 94
Accrued Liabilities: Accrued Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 | Sep. 30, 2015 |
Payables and Accruals [Abstract] | |||
Accrued employee compensation, benefits and withholdings | $ 57,203 | $ 43,342 | $ 43,390 |
Accrued property taxes | 37,156 | 32,393 | 30,669 |
Accrued payments related to litigation expenses and settlements | 0 | 38,750 | 33,375 |
Customer deposits and prepayments | 51,137 | 53,496 | 33,225 |
Accrued interest and contract adjustment payments | 42,612 | 25,762 | 22,839 |
CIAC current portion | 5,465 | 14,745 | 16,604 |
Other (none of which is individually significant) | 34,949 | 23,573 | 49,787 |
Total accrued liabilities | $ 228,522 | $ 232,061 | $ 229,889 |