Document and Entity Information
Document and Entity Information Document - shares | 9 Months Ended | |
Sep. 30, 2018 | Nov. 01, 2018 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | BLACK HILLS CORP /SD/ | |
Entity Central Index Key | 1,130,464 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,018 | |
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 | 59,974,620 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Income Statement [Abstract] | ||||
Revenue | $ 321,979 | $ 335,611 | $ 1,253,072 | $ 1,224,968 |
Operating expenses: | ||||
Fuel, purchased power and cost of natural gas sold | 80,244 | 86,281 | 432,544 | 404,222 |
Operations and maintenance | 115,477 | 109,258 | 350,099 | 335,707 |
Depreciation, depletion and amortization | 49,046 | 47,109 | 146,345 | 140,636 |
Taxes - property, production and severance | 11,905 | 12,408 | 39,181 | 38,866 |
Other operating expenses | 222 | 996 | 1,993 | 5,996 |
Total operating expenses | 256,894 | 256,052 | 970,162 | 925,427 |
Operating income | 65,085 | 79,559 | 282,910 | 299,541 |
Interest charges - | ||||
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts) | (36,480) | (35,287) | (107,360) | (105,417) |
Allowance for funds used during construction - borrowed | 701 | 753 | 1,345 | 2,061 |
Capitalized interest | 100 | 64 | 177 | 197 |
Interest income | 382 | 402 | 1,012 | 700 |
Allowance for funds used during construction - equity | 193 | 696 | 503 | 1,982 |
Other income (expense), net | (703) | 189 | (2,426) | (6) |
Total other income (expense), net | (35,807) | (33,183) | (106,749) | (100,483) |
Income before income taxes | 29,278 | 46,376 | 176,161 | 199,058 |
Income tax benefit (expense) | (7,477) | (13,478) | 11,784 | (58,518) |
Income from continuing operations | 21,801 | 32,898 | 187,945 | 140,540 |
Net (loss) from discontinued operations | (857) | (1,300) | (5,627) | (3,485) |
Net income | 20,944 | 31,598 | 182,318 | 137,055 |
Net income attributable to noncontrolling interest | (3,994) | (3,935) | (10,447) | (10,674) |
Net income from continuing operations | 17,807 | 28,963 | 177,498 | 129,866 |
Net income available for common stock | $ 16,950 | $ 27,663 | $ 171,871 | $ 126,381 |
Earnings Per Share, Basic [Abstract] | ||||
Income from continuing operations, Basic (usd per share) | $ 0.33 | $ 0.54 | $ 3.33 | $ 2.44 |
(Loss) from discontinued operations, Basic (usd per share) | (0.02) | (0.02) | (0.10) | (0.06) |
Earnings (loss) per share, Basic (usd per share) | 0.32 | 0.52 | 3.22 | 2.38 |
Earnings Per Share, Diluted [Abstract] | ||||
Income from continuing operations, Diluted (usd per share) | 0.32 | 0.52 | 3.26 | 2.35 |
(Loss) from discontinued operations, Diluted (usd per share) | (0.02) | (0.02) | (0.10) | (0.06) |
Earnings (loss) per share, Diluted (usd per share) | $ 0.31 | $ 0.50 | $ 3.15 | $ 2.29 |
Weighted Average Number of Shares Outstanding, Basic and Diluted [Abstract] | ||||
Basic (in shares) | 53,364 | 53,243 | 53,346 | 53,208 |
Diluted (in shares) | 54,819 | 55,432 | 54,508 | 55,254 |
Dividends declared per share of common stock (usd per share) | $ 0.475 | $ 0.445 | $ 1.425 | $ 1.335 |
Condensed Consolidated Statem_2
Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net income | $ 20,944 | $ 31,598 | $ 182,318 | $ 137,055 |
Other comprehensive income (loss), net of tax: | ||||
Reclassification adjustments of benefit plan liability - prior service cost | (34) | (32) | (104) | (94) |
Reclassification adjustments of benefit plan liability - net gain (loss) | 483 | 269 | 1,456 | 797 |
Other comprehensive income (loss), net of tax | 1,060 | 375 | 3,481 | 2,317 |
Comprehensive income | 22,004 | 31,973 | 185,799 | 139,372 |
Less: comprehensive income attributable to noncontrolling interest | (3,994) | (3,935) | (10,447) | (10,674) |
Comprehensive income available for common stock | 18,010 | 28,038 | 175,352 | 128,698 |
Interest rate swaps | ||||
Other comprehensive income (loss), net of tax: | ||||
Reclassification of net realized (gains) losses | 560 | 464 | 1,682 | 1,449 |
Commodity Contract | ||||
Other comprehensive income (loss), net of tax: | ||||
Reclassification of net realized (gains) losses | 21 | (166) | 615 | (590) |
Net unrealized gains (losses) | $ 30 | $ (160) | $ (168) | $ 755 |
Condensed Consolidated Statem_3
Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reclassification adjustment of benefit plan - prior service cost, (tax) benefit | $ 10 | $ 17 | $ 29 | $ 52 |
Reclassification adjustment of benefit plan liabilities, (tax) benefit | (138) | (145) | (409) | (445) |
Interest rate swaps | ||||
Reclassification of net realized gains/losses, (tax) benefit | (152) | (249) | (456) | (779) |
Commodity Contract | ||||
Net unrealized gains/losses, (tax) benefit | 0 | 94 | 51 | (442) |
Reclassification of net realized gains/losses, (tax) benefit | $ 3 | $ 95 | $ (187) | $ 344 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Current assets: | |||
Cash and cash equivalents | $ 10,001 | $ 15,420 | $ 13,449 |
Restricted cash | 3,241 | 2,820 | 2,683 |
Accounts receivable, net | 152,796 | 248,330 | 150,325 |
Materials, supplies and fuel | 122,618 | 113,283 | 122,866 |
Derivative assets, current | 1,392 | 304 | 433 |
Income tax receivable, net | 11,025 | 0 | 0 |
Regulatory assets, current | 48,302 | 81,016 | 61,023 |
Other current assets | 32,691 | 25,367 | 25,586 |
Current assets held for sale | 2,854 | 84,242 | 8,653 |
Total current assets | 384,920 | 570,782 | 385,018 |
Investments | 41,202 | 13,090 | 12,947 |
Property, plant and equipment | 5,819,000 | 5,567,518 | 5,499,557 |
Less: accumulated depreciation and depletion | (1,118,783) | (1,026,088) | (1,000,875) |
Total property, plant and equipment, net | 4,700,217 | 4,541,430 | 4,498,682 |
Other assets: | |||
Goodwill | 1,299,454 | 1,299,454 | 1,299,454 |
Intangible assets, net | 6,954 | 7,559 | 7,765 |
Regulatory assets, non-current | 212,048 | 216,438 | 239,571 |
Other assets, non-current | 17,143 | 10,149 | 11,626 |
Noncurrent assets held for sale | 0 | 0 | 108,685 |
Total other assets, non-current | 1,535,599 | 1,533,600 | 1,667,101 |
TOTAL ASSETS | 6,661,938 | 6,658,902 | 6,563,748 |
Current liabilities: | |||
Accounts payable | 115,900 | 160,887 | 94,790 |
Accrued liabilities | 201,353 | 219,462 | 206,779 |
Derivative liabilities, current | 1,154 | 2,081 | 1,458 |
Accrued income taxes, net | 0 | 1,022 | 5,587 |
Regulatory liabilities, current | 41,442 | 6,832 | 7,042 |
Notes payable | 112,100 | 211,300 | 225,170 |
Current maturities of long-term debt | 255,743 | 5,743 | 5,743 |
Current liabilities held for sale | 2,538 | 41,774 | 7,701 |
Total current liabilities | 730,230 | 649,101 | 554,270 |
Long-term debt | 2,951,389 | 3,109,400 | 3,109,864 |
Deferred credits and other liabilities: | |||
Deferred income tax liabilities, net | 292,753 | 336,520 | 618,315 |
Regulatory liabilities, non-current | 508,846 | 478,294 | 198,189 |
Benefit plan liabilities | 151,613 | 159,646 | 149,803 |
Other deferred credits and other liabilities | 105,928 | 105,735 | 113,996 |
Non-current liabilities held for sale | 0 | 0 | 23,329 |
Total deferred credits and other liabilities | 1,059,140 | 1,080,195 | 1,103,632 |
Commitments and contingencies (See Notes 9, 11, 16, 17) | |||
Equity: | |||
Common stock $1 par value; 100,000,000 shares authorized; issued 53,661,863; 53,579,986; and 53,524,529 shares, respectively | 53,662 | 53,580 | 53,525 |
Additional paid-in capital | 1,157,214 | 1,150,285 | 1,147,922 |
Retained earnings | 644,154 | 548,617 | 516,371 |
Treasury stock, at cost – 72,915; 39,064; and 41,457 shares, respectively | (4,072) | (2,306) | (2,448) |
Accumulated other comprehensive income (loss) | (37,703) | (41,202) | (32,566) |
Total stockholders’ equity | 1,813,255 | 1,708,974 | 1,682,804 |
Noncontrolling interest | 107,924 | 111,232 | 113,178 |
Total equity | 1,921,179 | 1,820,206 | 1,795,982 |
TOTAL LIABILITIES AND TOTAL EQUITY | $ 6,661,938 | $ 6,658,902 | $ 6,563,748 |
Condensed Consolidated Balanc_2
Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - $ / shares | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Statement of Financial Position [Abstract] | |||
Common Stock, Par Value (usd per share) | $ 1 | $ 1 | $ 1 |
Common Stock, Shares Issued | 53,661,863 | 53,579,986 | 53,524,529 |
Treasury Stock, Shares | 72,915 | 39,064 | 41,457 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 | 100,000,000 |
Condensed Consolidated Statem_4
Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Operating activities: | ||
Net income | $ 182,318 | $ 137,055 |
Loss from discontinued operations, net of tax | 5,627 | 3,485 |
Income from continuing operations | 187,945 | 140,540 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 146,345 | 140,636 |
Deferred financing cost amortization | 5,682 | 6,212 |
Stock compensation | 7,544 | 7,594 |
Deferred income taxes | (14,396) | 65,536 |
Employee benefit plans | 10,641 | 8,470 |
Other adjustments, net | 7,668 | (3,549) |
Changes in certain operating assets and liabilities: | ||
Materials, supplies and fuel | (8,380) | (19,511) |
Accounts receivable, unbilled revenues and other operating assets | 72,061 | 103,963 |
Accounts payable and other operating liabilities | (86,604) | (112,288) |
Regulatory assets - current | 41,655 | 1,287 |
Regulatory liabilities - current | 21,416 | (4,328) |
Contributions to defined benefit pension plans | (12,700) | (27,700) |
Other operating activities, net | 2,007 | (1,410) |
Net cash provided by operating activities of continuing operations | 380,884 | 305,452 |
Net cash provided by (used in) operating activities of discontinued operations | (2,162) | 13,978 |
Net cash provided by operating activities | 378,722 | 319,430 |
Investing activities: | ||
Property, plant and equipment additions | (278,132) | (238,840) |
Purchase of investment | (24,429) | 0 |
Other investing activities | 2,766 | 160 |
Net cash provided by (used in) investing activities of continuing operations | (299,795) | (238,680) |
Net cash provided by (used in) investing activities of discontinued operations | 18,024 | (17,298) |
Net cash provided by (used in) investing activities | (281,771) | (255,978) |
Financing activities: | ||
Dividends paid on common stock | (76,309) | (71,334) |
Common stock issued | 1,079 | 3,562 |
Net (payments) borrowings of short-term debt | (99,200) | 128,570 |
Proceeds from Issuance of Long-term Debt | 700,000 | 0 |
Long-term debt - repayments | (603,307) | (104,307) |
Distributions to noncontrolling interest | (13,755) | (12,884) |
Other financing activities | (10,457) | (6,719) |
Net cash provided by (used in) financing activities | (101,949) | (63,112) |
Net change in cash, cash equivalents and restricted cash | (4,998) | 340 |
Cash, cash equivalents and restricted cash at beginning of period | 18,240 | 15,792 |
Cash, cash equivalents and restricted cash at end of period | $ 13,242 | $ 16,132 |
Management's Statement_
Management's Statement: | 9 Months Ended |
Sep. 30, 2018 | |
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 2017 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 and Mining. 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. On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 for more information on discontinued operations. Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2018 , December 31, 2017 , and September 30, 2017 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, 2018 and September 30, 2017 , and our financial condition as of September 30, 2018 , December 31, 2017 , and September 30, 2017 , 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. Cash and Cash Equivalents and Restricted Cash For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents. Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the nine months ended September 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows. |
Revenue_
Revenue: | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue | REVENUE Revenue Recognition Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered. • Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 157,049 $ 88,559 $ — $ 16,751 $ (7,941 ) $ 254,418 Transportation — 30,079 — — (267 ) 29,812 Wholesale 8,255 — 14,485 — (13,047 ) 9,693 Market - off-system sales 9,059 140 — — (1,349 ) 7,850 Transmission/Other 10,196 11,887 — — (3,693 ) 18,390 Revenue from contracts with customers 184,559 130,665 14,485 16,751 (26,297 ) 320,163 Other revenues 231 1,011 9,118 550 (9,094 ) 1,816 Total revenues $ 184,790 $ 131,676 $ 23,603 $ 17,301 $ (35,391 ) $ 321,979 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,751 $ (7,941 ) $ 8,810 Services transferred over time 184,559 130,665 14,485 — (18,356 ) 311,353 Revenue from contracts with customers $ 184,559 $ 130,665 $ 14,485 $ 16,751 $ (26,297 ) $ 320,163 Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 449,482 $ 565,816 $ — $ 49,653 $ (23,761 ) $ 1,041,190 Transportation — 100,760 — — (977 ) 99,783 Wholesale 25,497 — 41,161 — (36,874 ) 29,784 Market - off-system sales 18,142 728 — — (5,531 ) 13,339 Transmission/Other 36,622 36,230 — — (10,967 ) 61,885 Revenue from contracts with customers 529,743 703,534 41,161 49,653 (78,110 ) 1,245,981 Other revenues 2,218 3,106 27,429 1,675 (27,337 ) 7,091 Total revenues $ 531,961 $ 706,640 $ 68,590 $ 51,328 $ (105,447 ) $ 1,253,072 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 49,653 $ (23,761 ) $ 25,892 Services transferred over time 529,743 703,534 41,161 — (54,349 ) 1,220,089 Revenue from contracts with customers $ 529,743 $ 703,534 $ 41,161 $ 49,653 $ (78,110 ) $ 1,245,981 The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20 -year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018 , respectively. As of September 30, 2018 , $7.9 million has been returned to customers and approximately $21 million remains in reserve. Unbilled Revenue Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance. |
Business Segment Information_
Business Segment Information: | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting Information, Additional Information [Abstract] | |
Business Segment Information | BUSINESS SEGMENT INFORMATION Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands): Three Months Ended September 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric Utilities $ 179,527 $ 231 $ 5,032 $ — $ 184,790 $ 21,578 Gas Utilities 130,390 1,011 275 — 131,676 (13,277 ) Power Generation (b) 1,437 348 13,048 8,770 23,603 6,691 Mining 8,809 226 7,942 324 17,301 3,572 Corporate and Other — — — — — (757 ) Inter-company eliminations — — (26,297 ) (9,094 ) (35,391 ) — Total $ 320,163 $ 1,816 $ — $ — $ 321,979 $ 17,807 Under our modified retrospective adoption of ASU 2014-09, revenues for the three and nine months ended September 30, 2017 are not presented by contract type. Three Months Ended September 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric Utilities $ 181,238 $ 2,333 $ 27,324 Gas Utilities 142,821 73 (4,329 ) Power Generation (b) 1,810 21,117 6,155 Mining 9,742 7,751 3,477 Corporate and Other — — (3,664 ) Inter-company eliminations — (31,274 ) — Total $ 335,611 $ — $ 28,963 Nine Months Ended September 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric Utilities $ 513,270 $ 2,218 $ 16,473 $ — $ 531,961 $ 63,313 Gas Utilities (a) 702,532 3,106 1,002 — 706,640 93,182 Power Generation (b) 4,287 1,066 36,874 26,363 68,590 17,319 Mining 25,892 701 23,761 974 51,328 9,561 Corporate and Other — — — — — (5,877 ) Inter-company eliminations — — (78,110 ) (27,337 ) (105,447 ) — Total $ 1,245,981 $ 7,091 $ — $ — $ 1,253,072 $ 177,498 Nine Months Ended September 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric Utilities $ 518,925 $ 9,123 $ 68,386 Gas Utilities 674,161 90 41,409 Power Generation (b) 5,382 62,907 18,017 Mining 26,500 22,485 9,048 Corporate and Other (c) — — (6,994 ) Inter-company eliminations — (94,605 ) — Total $ 1,224,968 $ — $ 129,866 ___________ (a) Net income from continuing operations available for common stock for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information. (b) Net income from continuing operations available for common stock for the three and nine months ended September 30, 2018 and September 30, 2017 reflects net income attributable to noncontrolling interests of $4.0 million and $10.4 million , and $3.9 million and $10.6 million , respectively. (c) Net income (loss) from continuing operations available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Segment information and Corporate and Other 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, 2018 December 31, 2017 September 30, 2017 Segment: Electric Utilities (a) $ 2,853,414 $ 2,906,275 $ 2,911,919 Gas Utilities 3,433,316 3,426,466 3,288,104 Power Generation (a) 122,428 60,852 64,357 Mining 72,602 65,455 66,700 Corporate and Other 177,324 115,612 115,330 Discontinued operations 2,854 84,242 117,338 Total assets $ 6,661,938 $ 6,658,902 $ 6,563,748 __________ (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 as a capital lease. |
Accounts Receivable_
Accounts Receivable: | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 43,108 $ 31,381 $ (386 ) $ 74,103 Gas Utilities 48,638 24,768 (2,188 ) 71,218 Power Generation 1,696 — — 1,696 Mining 3,749 — — 3,749 Corporate 2,030 — — 2,030 Total $ 99,221 $ 56,149 $ (2,574 ) $ 152,796 Accounts Unbilled Less Allowance for Accounts December 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 Accounts Unbilled Less Allowance for Accounts September 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 42,716 $ 29,762 $ (494 ) $ 71,984 Gas Utilities 49,842 24,516 (1,190 ) 73,168 Power Generation 1,010 — — 1,010 Mining 3,534 — — 3,534 Corporate 629 — — 629 Total $ 97,731 $ 54,278 $ (1,684 ) $ 150,325 |
Regulatory Accounting_
Regulatory Accounting: | 9 Months Ended |
Sep. 30, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Accounting | REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 29,976 $ 20,187 $ 20,559 Deferred gas cost adjustments (a) 720 31,844 12,833 Gas price derivatives (a) 6,192 11,935 11,297 Deferred taxes on AFUDC (b) 7,804 7,847 15,645 Employee benefit plans (c) 106,734 109,235 105,671 Environmental (a) 972 1,031 1,051 Asset retirement obligations (a) 526 517 514 Loss on reacquired debt (a) 21,431 20,667 21,067 Renewable energy standard adjustment (a) 1,131 1,088 1,956 Deferred taxes on flow through accounting (c) (e) 29,342 26,978 41,900 Decommissioning costs (b) 11,052 13,287 13,989 Gas supply contract termination (a) 15,745 20,001 21,402 Other regulatory assets (a) 28,725 32,837 32,710 Total regulatory assets 260,350 297,454 300,594 Less current regulatory assets (48,302 ) (81,016 ) (61,023 ) Regulatory assets, non-current $ 212,048 $ 216,438 $ 239,571 Regulatory liabilities Deferred energy and gas costs (a) $ 15,980 $ 3,427 $ 3,780 Employee benefit plan costs and related deferred taxes (c) (e) 39,332 40,629 66,620 Cost of removal (a) 146,177 130,932 125,360 Excess deferred income taxes (c) (d) 316,625 301,553 52 TCJA revenue reserve 20,592 — — Other regulatory liabilities (c) 11,582 8,585 9,419 Total regulatory liabilities 550,288 485,126 205,231 Less current regulatory liabilities (41,442 ) (6,832 ) (7,042 ) Regulatory liabilities, non-current $ 508,846 $ 478,294 $ 198,189 __________ (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) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of September 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets. (e) The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA. Regulatory Matters Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K. TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018 , respectively. As of September 30, 2018 , $7.9 million has been returned to customers. A list of states where benefits to customers of federal tax reform have been approved is summarized below. State Approximate 2018 Benefit for Customers Start Date for Customer Benefits Arkansas $ 9.7 million October 2018 Colorado $ 10.8 million July 2018 Iowa $ 2.4 million June 2018 Kansas $ 1.9 million April 2018 Nebraska $ 3.8 million July 2018 South Dakota $ 7.7 million October 2018 In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below. Rate Reviews RMNG In Colorado, new rates for RMNG went into effect June 1, 2018 after an administrative law judge recommended approval of a settlement agreement and the CPUC took no further action. The settlement included $1.1 million in annual revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA. Wyoming Gas On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6% , and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018. Arkansas Gas On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018. Wyoming Electric On October 31, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide an aggregate $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of September 30, 2018, we have recorded a liability of $4.5 million related to the PCA. Nebraska Gas On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NSPC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered. Kansas Gas On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission to double annual eligible investments up to $8.0 million for safety related integrity investments under the Gas System Reliability rider. |
Materials, Supplies and Fuel_
Materials, Supplies and Fuel: | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 December 31, 2017 September 30, 2017 Materials and supplies $ 73,777 $ 69,732 $ 70,284 Fuel - Electric Utilities 2,750 2,962 2,993 Natural gas in storage held for distribution 46,091 40,589 49,589 Total materials, supplies and fuel $ 122,618 $ 113,283 $ 122,866 |
Investments_
Investments: | 9 Months Ended |
Sep. 30, 2018 | |
Long-term Investments [Abstract] | |
Investments | INVESTMENTS In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of September 30, 2018 . The following table presents the carrying value of our investments (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Cost method investment $ 28,134 $ — $ — Cash surrender value of life insurance contracts 13,068 13,090 12,947 Total investments $ 41,202 $ 13,090 $ 12,947 |
Earnings Per Share_
Earnings Per Share: | 9 Months Ended |
Sep. 30, 2018 | |
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 was as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Net income available for common stock $ 16,950 $ 27,663 $ 171,871 $ 126,381 Weighted average shares - basic 53,364 53,243 53,346 53,208 Dilutive effect of: Equity Units (a) 1,344 2,015 1,060 1,872 Equity compensation 111 174 102 174 Weighted average shares - diluted 54,819 55,432 54,508 55,254 __________ (a) Calculated using the treasury stock method. 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, 2018 2017 2018 2017 Equity compensation 12 — 15 — Anti-dilutive shares 12 — 15 — |
Notes Payable, Current Maturiti
Notes Payable, Current Maturities and Debt: | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Notes Payable, Current Maturities and Debt | NOTES PAYABLE, CURRENT MATURITIES AND DEBT We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 15,203 $ — $ 26,848 $ — $ 25,391 CP Program 112,100 — 211,300 — 225,170 — Total $ 112,100 $ 15,203 $ 211,300 $ 26,848 $ 225,170 $ 25,391 Revolving Credit Facility and CP Program On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one -year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 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 Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term 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, 2018 . Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at September 30, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P. We have a $750 million , unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million . The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net payments under the CP Program during the nine months ended September 30, 2018 were $99 million and our notes outstanding as of September 30, 2018 were $112 million . As of September 30, 2018 , the weighted average interest rate on CP Program borrowings was 2.42% . Debt Covenants Under our Revolving Credit Facility and term loan agreement (before each was amended and restated), we were required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 . At September 30, 2018, our Consolidated Indebtedness to Capitalization Ratio was calculated by dividing (i) Consolidated Indebtedness (which included letters of credit and certain guarantees issued but excluded the RSNs), by (ii) Capital, which is Consolidated Indebtedness plus Consolidated Net Worth (which excluded noncontrolling interests in subsidiaries and included the aggregate outstanding amount of the RSNs). Under our amended and restated revolving Credit Facility and amended and restated term loan agreement, we are also required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 , but as of September 30, 2018 only, Consolidated Net Worth will include the amount receivable by the Company in connection with the common stock settlement under the purchase contracts which are part of the Equity Units, rather than the outstanding amount of the RSNs. Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter: As of September 30, 2018 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 61.4% Less than 65% As of September 30, 2018 , we were in compliance with this covenant. Current Maturities As of September 30, 2018 , our $250 million senior unsecured notes due January 11, 2019 and $5.7 million of principal due in the next twelve months on our Corporate term loan due June 7, 2021 are classified as Current maturities of long-term debt on our Condensed Consolidated Balance Sheets. Long-Term Debt On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt. The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see subsequent event in Note 10). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate). On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at September 30, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.000% and 0.700% , respectively, at September 30, 2018. |
Equity_
Equity: | 9 Months Ended |
Sep. 30, 2018 | |
Statement of Stockholders' Equity [Abstract] | |
Equity | EQUITY A summary of the changes in equity is as follows: Nine Months Ended September 30, 2018 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2017 $ 1,708,974 $ 111,232 $ 1,820,206 Net income (loss) 171,871 10,447 182,318 Other comprehensive income 3,481 — 3,481 Dividends on common stock (76,309 ) — (76,309 ) Share-based compensation 4,871 — 4,871 Dividend reinvestment and stock purchase plan 220 — 220 Other stock transactions 147 — 147 Distribution to noncontrolling interest — (13,755 ) (13,755 ) Balance at September 30, 2018 $ 1,813,255 $ 107,924 $ 1,921,179 Nine Months Ended September 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 126,381 10,567 136,948 Other comprehensive income 2,317 — 2,317 Dividends on common stock (71,334 ) — (71,334 ) Share-based compensation 5,853 — 5,853 Dividend reinvestment and stock purchase plan 2,300 — 2,300 Redeemable noncontrolling interest (886 ) — (886 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (180 ) — (180 ) Distribution to noncontrolling interest — (12,884 ) (12,884 ) Balance at September 30, 2017 $ 1,682,804 $ 113,178 $ 1,795,982 At-the-Market Equity Offering Program On August 4, 2017, we renewed our ATM equity offering program which reset the size of the program to an aggregate value of up to $300 million . The renewed program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $200 million to $300 million . The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the nine months ended September 30, 2018 or September 30, 2017 under the ATM equity offering program. Subsequent Event - Equity Units Settlement On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds will be used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt. As of November 1, 2018, after the Equity Units settlement, we had shares outstanding of approximately 59.97 million . |
Risk Management Activities_
Risk Management Activities: | 9 Months Ended |
Sep. 30, 2018 | |
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 2017 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 retail natural gas marketing activities and our fuel procurement for certain 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 and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 12 . 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, over-the-counter 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. We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from October 2018 through May 2020; a portion of these swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives 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. Effectiveness of our hedging position is evaluated at inception of the hedge, upon occurrence of a triggering event and as of the end of each quarter. 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, 2018 December 31, 2017 September 30, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 5,300,000 27 8,330,000 36 10,250,000 39 Natural gas options purchased, net 9,670,000 16 3,540,000 14 7,360,000 17 Natural gas basis swaps purchased 5,140,000 27 8,060,000 36 9,170,000 39 Natural gas over-the-counter swaps, net (b) 4,370,000 20 3,820,000 29 4,600,000 20 Natural gas physical contracts, net (c) 19,539,851 33 12,826,605 35 21,071,714 38 __________ (a) Term reflects the maximum forward period hedged. (b) As of September 30, 2018 , 2,236,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (c) Volumes exclude contracts that qualify for the normal purchase, normal sales exception. Based on September 30, 2018 prices, a $0.1 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2018 , the Company posted $0.7 million related to such provisions, which is included in Other current assets on the Condensed Consolidated Balance Sheets. Financing Activities At September 30, 2018 , we had no outstanding interest rate swap agreements. Our last interest rate swap agreement with a $50 million notional value, which was designated to borrowings on our Revolving Credit Facility, expired in January 2017. Discontinued Operations Our Oil and Gas segment was exposed to risks associated with changes in the market prices of oil and gas. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas assets, these activities were discontinued and there were no outstanding derivative agreements as of September 30, 2018 or December 31, 2017. At September 30, 2017, we had outstanding crude oil futures and swap contracts with notional volumes of 54,000 Bbls, crude oil option contracts with notional volumes of 9,000 Bbls and natural gas futures and swap contracts with notional volumes of 540,000 MMBtus. Cash Flow Hedges The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended September 30, 2018 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (712 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (18 ) Fuel, purchased power and cost of natural gas sold — Total $ (730 ) $ — Three Months Ended September 30, 2017 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (713 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 295 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (34 ) Fuel, purchased power and cost of natural gas sold — Total $ (452 ) $ — Nine Months Ended September 30, 2018 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (2,138 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (802 ) Fuel, purchased power and cost of natural gas sold — Total $ (2,940 ) $ — Nine Months Ended September 30, 2017 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (2,228 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 954 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (20 ) Fuel, purchased power and cost of natural gas sold — Total $ (1,294 ) $ — The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2018 and 2017 . The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred. Three Months Ended September 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ 30 $ (254 ) Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 712 713 Forward commodity contracts 18 (261 ) Total other comprehensive income (loss) from hedging $ 760 $ 198 Nine Months Ended September 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ (219 ) $ 1,197 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,138 2,228 Forward commodity contracts 802 (934 ) Total other comprehensive income (loss) from hedging $ 2,721 $ 2,491 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended September 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ (53 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold (96 ) (322 ) $ (96 ) $ (375 ) Nine Months Ended September 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 90 Commodity derivatives Fuel, purchased power and cost of natural gas sold 929 (1,822 ) $ 929 $ (1,732 ) As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our utilities were $6.2 million , $12 million and $11 million at September 30, 2018 , December 31, 2017 and September 30, 2017 , respectively. |
Fair Value Measurements_
Fair Value Measurements: | 9 Months Ended |
Sep. 30, 2018 | |
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 2017 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 Discontinued Operations: • Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. Utilities Segments: • The commodity contracts for our Utilities Segments, are valued using the market approach and include exchange-traded futures, options, basis swaps and over-the-counter swaps and options (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: • As of September 30, 2018 , we no longer have derivatives within our corporate activities as our last interest rate swaps matured in January 2017. 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. Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 18. The following tables set forth by level within the fair value hierarchy present 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, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 5,882 $ — $ (4,469 ) $ 1,413 Total $ — $ 5,882 $ — $ (4,469 ) $ 1,413 Liabilities: Commodity derivatives — Utilities $ — $ 10,033 $ — $ (8,777 ) $ 1,256 Total $ — $ 10,033 $ — $ (8,777 ) $ 1,256 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives — Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of September 30, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 2,880 $ — $ (2,448 ) $ 432 Total $ — $ 2,880 $ — $ (2,448 ) $ 432 Liabilities: Commodity derivatives — Utilities $ — $ 12,647 $ — $ (11,125 ) $ 1,522 Total $ — $ 12,647 $ — $ (11,125 ) $ 1,522 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. The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of September 30, 2018 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 142 $ — Commodity derivatives Other assets, non-current 21 — Commodity derivatives Derivative liabilities — current — 273 Commodity derivatives Other deferred credits and other liabilities — 10 Total derivatives designated as hedges $ 163 $ 283 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,250 $ — Commodity derivatives Derivative liabilities — current — 881 Commodity derivatives Other deferred credits and other liabilities — 92 Total derivatives not designated as hedges $ 1,250 $ 973 As of December 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative liabilities — current $ — $ 817 Commodity derivatives Other deferred credits and other liabilities — 67 Total derivatives designated as hedges $ — $ 884 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 304 $ — Commodity derivatives Derivative liabilities — current — 1,264 Commodity derivatives Other deferred credits and other liabilities — 111 Total derivatives not designated as hedges $ 304 $ 1,375 As of September 30, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2 $ — Commodity derivatives Current assets held for sale 225 — Commodity derivatives Derivative liabilities — current — 422 Commodity derivatives Current liabilities held for sale — 89 Commodity derivatives Other deferred credits and other liabilities — 49 Commodity derivatives Noncurrent liabilities held for sale — 10 Total derivatives designated as hedges $ 227 $ 570 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 430 $ — Commodity derivatives Derivative liabilities — current — 1,036 Commodity derivatives Other deferred credits and other liabilities — 15 Commodity derivatives Noncurrent liabilities held for sale — 15 Total derivatives not designated as hedges $ 430 $ 1,066 Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2017 Annual Report on Form 10-K. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments: | 9 Months Ended |
Sep. 30, 2018 | |
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 12 , were as follows (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 10,001 $ 10,001 $ 15,420 $ 15,420 $ 13,449 $ 13,449 Restricted cash (a) $ 3,241 $ 3,241 $ 2,820 $ 2,820 $ 2,683 $ 2,683 Notes payable (b) $ 112,100 $ 112,100 $ 211,300 $ 211,300 $ 225,170 $ 225,170 Long-term debt, including current maturities (c) (d) $ 3,207,132 $ 3,289,770 $ 3,115,143 $ 3,350,544 $ 3,115,607 $ 3,362,971 __________ (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) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) 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. (d) Carrying amount of long-term debt is net of deferred financing costs. |
Other Comprehensive Income (Los
Other Comprehensive Income (Loss): | 9 Months Ended |
Sep. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | |
Other Comprehensive Income (Loss) | OTHER COMPREHENSIVE INCOME (LOSS) We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three Months Ended Nine Months Ended September 30, 2018 September 30, 2017 September 30, 2018 September 30, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (712 ) $ (713 ) $ (2,138 ) $ (2,228 ) Commodity contracts Net (loss) from discontinued operations — 295 — 954 Commodity contracts Fuel, purchased power and cost of natural gas sold (18 ) (34 ) (802 ) (20 ) (730 ) (452 ) (2,940 ) (1,294 ) Income tax Income tax benefit (expense) 149 154 643 435 Total reclassification adjustments related to cash flow hedges, net of tax $ (581 ) $ (298 ) $ (2,297 ) $ (859 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 44 $ 49 $ 133 $ 146 Actuarial gain (loss) Operations and maintenance (621 ) (414 ) (1,865 ) (1,242 ) (577 ) (365 ) (1,732 ) (1,096 ) Income tax Income tax benefit (expense) 128 128 380 393 Total reclassification adjustments related to defined benefit plans, net of tax $ (449 ) $ (237 ) $ (1,352 ) $ (703 ) Total reclassifications $ (1,030 ) $ (535 ) $ (3,649 ) $ (1,562 ) Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — (168 ) — (168 ) Amounts reclassified from AOCI 1,682 615 1,352 3,649 Reclassifications of certain tax effects from AOCI 15 — 3 18 Ending Balance September 30, 2018 $ (17,884 ) $ (71 ) $ (19,748 ) $ (37,703 ) Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 755 — 755 Amounts reclassified from AOCI 1,449 (590 ) 703 1,562 Ending Balance September 30, 2017 $ (16,660 ) $ (68 ) $ (15,838 ) $ (32,566 ) |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information: | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended September 30, 2018 September 30, 2017 (in thousands) Non-cash investing and financing activities — Property, plant and equipment acquired with accrued liabilities $ 49,631 $ 33,409 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 155 $ 1,362 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (104,035 ) $ (102,008 ) Income taxes (paid) refunded $ (14,842 ) $ 1 |
Employee Benefit Plans_
Employee Benefit Plans: | 9 Months Ended |
Sep. 30, 2018 | |
Defined Benefit Plan [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Benefit Pension Plan The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Service cost $ 1,708 $ 1,759 $ 5,125 $ 5,276 Interest cost 3,867 3,880 11,602 11,640 Expected return on plan assets (6,185 ) (6,130 ) (18,555 ) (18,388 ) Prior service cost 15 15 44 44 Net loss (gain) 2,158 1,002 6,473 3,005 Net periodic benefit cost $ 1,563 $ 526 $ 4,689 $ 1,577 Defined Benefit Postretirement Healthcare Plans 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, 2018 2017 2018 2017 Service cost $ 573 $ 575 $ 1,718 $ 1,725 Interest cost 521 533 1,563 1,600 Expected return on plan assets (57 ) (79 ) (170 ) (237 ) Prior service cost (benefit) (99 ) (109 ) (297 ) (327 ) Net loss (gain) 54 125 162 375 Net periodic benefit cost $ 992 $ 1,045 $ 2,976 $ 3,136 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, 2018 2017 2018 2017 Service cost $ 632 $ 612 $ 1,347 $ 2,048 Interest cost 293 319 878 957 Prior service cost — — 1 1 Net loss (gain) 250 251 750 751 Net periodic benefit cost $ 1,175 $ 1,182 $ 2,976 $ 3,757 For the three and nine months ended September 30, 2018 , service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net, on the Condensed Consolidated Statements of Income. For the three and nine months ended September 30, 2017 , service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Consolidated Statements of Income. See Note 1 for additional information. Contributions Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 25, 2018, we made a contribution of approximately $13 million (included in the table below) to the Defined Benefit Pension Plan. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Anticipated for 2018 Anticipated for 2019 Defined Benefit Pension Plan $ 12,700 $ 12,700 $ — $ 12,700 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234 $ 3,702 $ 1,234 $ 3,821 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343 $ 1,029 $ 343 $ 1,623 |
Commitments and Contingencies_
Commitments and Contingencies: | 9 Months Ended |
Sep. 30, 2018 | |
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 19 of our Notes to the Consolidated Financial Statements in our 2017 Annual Report on Form 10-K except for those described below. Busch Ranch I Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and AltaGas. Colorado Electric has a 50% ownership interest in the wind farm. On September 20, 2018, Black Hills Electric Generation agreed to purchase AltaGas’s 50% interest in Busch Ranch for $16 million . The purchase, which is subject to FERC approval, is expected to be finalized by the end of 2018. 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, 2018 , 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. 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, 2018 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million . |
Discontinued Operations_
Discontinued Operations: | 9 Months Ended |
Sep. 30, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | DISCONTINUED OPERATIONS Results of operations for discontinued operations have been classified as Loss from discontinued operations, net of income taxes in the accompanying Condensed Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our condensed consolidated financial statements. Oil and Gas Segment On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. We expect to transfer any associated liabilities, and settle substantially all remaining liabilities by December 31, 2018. In the process of divesting our Oil and Gas segment, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent sales of assets and pending sale transactions of our other properties. There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made and how they compared with the additional property sales occurring after December 31, 2017. At December 31, 2017 , the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million . There were no further adjustments made to the fair value of our held for sale assets at September 30, 2018 . During the nine months ended September 30, 2018 , we recorded $2.9 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of BHEP assets. Total assets and liabilities of the Oil and Gas segment at September 30, 2018 and December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Condensed Consolidated Balance Sheets due to the expected final disposals occurring by the end of 2018. Held for sale assets and liabilities at September 30, 2017 are classified as current and non-current (in thousands): September 30, 2018 December 31, 2017 September 30, 2017 Other current assets $ 75 $ 10,360 $ 8,457 Derivative assets, current and noncurrent — — 225 Deferred income tax assets, noncurrent, net — 16,966 12,571 Property, plant and equipment, net 2,779 56,916 96,085 Other current liabilities (2,138 ) (18,966 ) (7,597 ) Derivative liabilities, current and noncurrent — — (114 ) Deferred income tax liabilities, noncurrent, net (400 ) — — Other noncurrent liabilities — (22,808 ) (23,319 ) Net assets (liabilities) $ 316 $ 42,468 $ 86,308 At September 30, 2018 , December 31, 2017 and September 30, 2017 , the Oil and Gas segment’s net deferred tax assets and liabilities were primarily comprised of basis differences on oil and gas properties. The Oil and Gas segment’s other current liabilities at September 30, 2018 consisted primarily of accrued royalties, payroll and property taxes. Current liabilities at December 31, 2017 consisted primarily of a liability contingent on final approval from the Bureau of Indian Affairs on the Jicarilla property sale, accrued royalties, payroll and property taxes. Current liabilities at September 30, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 and September 30, 2017 consisted primarily of asset retirement obligations relating to plugging and abandonment of oil and gas wells. |
Income Taxes_
Income Taxes: | 9 Months Ended |
Sep. 30, 2018 | |
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 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) (a) (6.3 ) (3.4 ) Percentage depletion in excess of cost (0.5 ) (0.9 ) Accounting for uncertain tax positions adjustment — (0.6 ) Noncontrolling interest (b) (1.3 ) (3.0 ) Tax credits (c) (5.3 ) (1.6 ) Effective tax rate adjustment (d) — 3.9 Flow-through adjustments (1.5 ) (1.6 ) TCJA change in estimate (e) 17.6 — AFUDC equity (0.1 ) — Other tax differences 1.9 1.3 25.5 % 29.1 % __________ (a) Adjustment to the deferred state rate and reduced state tax expense for the quarter. (b) The adjustment reflects the noncontrolling interest attributable to the sale in April 2016 of 49.9% of the membership interests of COIPP LLC. (c) The tax credits are due to the production tax credits for the Peak View wind farm. (d) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. (e) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended September 30, 2018, we recorded an additional $5.3 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. Nine Months Ended September 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 0.4 0.3 Percentage depletion in excess of cost (0.4 ) (0.6 ) Accounting for uncertain tax positions adjustment — (0.2 ) Noncontrolling interest (1.1 ) (1.9 ) IRC 172(f) carryback claim (a) — (1.0 ) Tax credits (b) (2.6 ) (1.6 ) Effective tax rate adjustment — 0.3 Flow-through adjustments (0.8 ) (1.2 ) TCJA change in estimate (c) 4.3 — AFUDC equity (0.1 ) — Jurisdictional simplification project (d) (28.1 ) — Other tax differences 0.7 0.3 (6.7 )% 29.4 % __________ (a) During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (b) The tax credits are due to the production tax credits for the Peak View wind farm. (c) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the nine months ended September 30, 2018, we recorded an additional $7.5 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. (d) Tax benefit from legal restructuring associated with amortizable goodwill as part of jurisdictional simplification. Tax benefit related to legal restructuring As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018. As a result of these transactions, $49 million of deferred income tax assets, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $49 million were recorded to income tax benefit (expense) on the Condensed Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities. TCJA - Deferred Taxes On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017, which reflected our provisional estimate of the impact of the TCJA, under SEC Staff Accounting Bulletin No. 118. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the state regulatory commissions. In addition to current year utility revenue reserves as disclosed in Note 5, we recorded additional changes in estimates of the provisional amounts recorded at December 31, 2017, primarily related to bonus depreciation and other plant and property items, after filing our 2017 tax returns which increased tax expense by $5.3 million for the three months, and decreased tax benefit by $7.5 million for the nine months ended September 30, 2018. We will continue to evaluate subsequent regulations, clarifications and interpretations of the assumptions made, which could change our estimates related to the TCJA, which we expect to finalize in the fourth quarter. |
Accrued Liabilities_
Accrued Liabilities: | 9 Months Ended |
Sep. 30, 2018 | |
Payables and Accruals [Abstract] | |
Accrued Liabilities | 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, 2018 December 31, 2017 September 30, 2017 Accrued employee compensation, benefits and withholdings $ 57,600 $ 52,467 $ 52,841 Accrued property taxes 37,660 42,029 36,993 Customer deposits and prepayments 42,002 44,420 41,012 Accrued interest and contract adjustment payments 31,139 33,822 30,977 CIAC current portion 1,552 1,552 1,575 Other (none of which is individually significant) 31,400 45,172 43,381 Total accrued liabilities $ 201,353 $ 219,462 $ 206,779 |
Subsequent Events_
Subsequent Events: | 9 Months Ended |
Sep. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS There are no subsequent events, other than those disclosed in Note 5 and Note 10. |
Management's Statement (Policie
Management's Statement (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
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 and Mining. 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. On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. The Oil and Gas segment assets and liabilities are classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, excluding certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As of September 30, 2018, we have sold nearly all of our oil and gas assets and we closed our oil and gas office in August. Transaction closing for the last few assets and final accounting are expected within the fourth quarter. See Note 18 for more information on discontinued operations. |
Use of Estimates and Basis of Presentation | Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2018 , December 31, 2017 , and September 30, 2017 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, 2018 and September 30, 2017 , and our financial condition as of September 30, 2018 , December 31, 2017 , and September 30, 2017 , 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. |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents and Restricted Cash For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents. |
Investments | Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. |
Recently Issued and Adopted Accounting Standards | Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the current guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We expect to adopt this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we anticipate electing the practical expedient which provides for no assessment of these easements. Further, we anticipate adopting the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We expect to elect the “package of three” practical expedient. We continue to evaluate the additional transition practical expedients available under the guidance. At this time, we do not believe the implementation of this standard will have a material impact on our financial position, results of operations or cash flows. We continue to develop our process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected, configured, and tested a new lease software solution and will be entering lease data into the new system in preparation for the January 1, 2019 standard adoption. We also continue to monitor utility industry lease implementation guidance that may change existing and future lease classification. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate the adoption of this guidance to have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this standard to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the nine months ended September 30, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows. |
Revenue Recognition | Revenue Recognition Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our electric utilities and power generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black Hills also sells excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered. • Other non-regulated services - Our natural gas and electric utility segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 157,049 $ 88,559 $ — $ 16,751 $ (7,941 ) $ 254,418 Transportation — 30,079 — — (267 ) 29,812 Wholesale 8,255 — 14,485 — (13,047 ) 9,693 Market - off-system sales 9,059 140 — — (1,349 ) 7,850 Transmission/Other 10,196 11,887 — — (3,693 ) 18,390 Revenue from contracts with customers 184,559 130,665 14,485 16,751 (26,297 ) 320,163 Other revenues 231 1,011 9,118 550 (9,094 ) 1,816 Total revenues $ 184,790 $ 131,676 $ 23,603 $ 17,301 $ (35,391 ) $ 321,979 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,751 $ (7,941 ) $ 8,810 Services transferred over time 184,559 130,665 14,485 — (18,356 ) 311,353 Revenue from contracts with customers $ 184,559 $ 130,665 $ 14,485 $ 16,751 $ (26,297 ) $ 320,163 Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 449,482 $ 565,816 $ — $ 49,653 $ (23,761 ) $ 1,041,190 Transportation — 100,760 — — (977 ) 99,783 Wholesale 25,497 — 41,161 — (36,874 ) 29,784 Market - off-system sales 18,142 728 — — (5,531 ) 13,339 Transmission/Other 36,622 36,230 — — (10,967 ) 61,885 Revenue from contracts with customers 529,743 703,534 41,161 49,653 (78,110 ) 1,245,981 Other revenues 2,218 3,106 27,429 1,675 (27,337 ) 7,091 Total revenues $ 531,961 $ 706,640 $ 68,590 $ 51,328 $ (105,447 ) $ 1,253,072 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 49,653 $ (23,761 ) $ 25,892 Services transferred over time 529,743 703,534 41,161 — (54,349 ) 1,220,089 Revenue from contracts with customers $ 529,743 $ 703,534 $ 41,161 $ 49,653 $ (78,110 ) $ 1,245,981 The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the tables above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20 -year power sale agreement between Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $6.0 million and $29 million during the three and nine months ended September 30, 2018 , respectively. As of September 30, 2018 , $7.9 million has been returned to customers and approximately $21 million remains in reserve. Unbilled Revenue Revenues attributable to natural gas and electricity delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues include estimates of delivered sales volumes based on weather information and customer consumption trends. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 4. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance. |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the three and nine months ended September 30, 2018 . Sales tax and other similar taxes are excluded from revenues. Three Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 157,049 $ 88,559 $ — $ 16,751 $ (7,941 ) $ 254,418 Transportation — 30,079 — — (267 ) 29,812 Wholesale 8,255 — 14,485 — (13,047 ) 9,693 Market - off-system sales 9,059 140 — — (1,349 ) 7,850 Transmission/Other 10,196 11,887 — — (3,693 ) 18,390 Revenue from contracts with customers 184,559 130,665 14,485 16,751 (26,297 ) 320,163 Other revenues 231 1,011 9,118 550 (9,094 ) 1,816 Total revenues $ 184,790 $ 131,676 $ 23,603 $ 17,301 $ (35,391 ) $ 321,979 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 16,751 $ (7,941 ) $ 8,810 Services transferred over time 184,559 130,665 14,485 — (18,356 ) 311,353 Revenue from contracts with customers $ 184,559 $ 130,665 $ 14,485 $ 16,751 $ (26,297 ) $ 320,163 Nine Months Ended September 30, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 449,482 $ 565,816 $ — $ 49,653 $ (23,761 ) $ 1,041,190 Transportation — 100,760 — — (977 ) 99,783 Wholesale 25,497 — 41,161 — (36,874 ) 29,784 Market - off-system sales 18,142 728 — — (5,531 ) 13,339 Transmission/Other 36,622 36,230 — — (10,967 ) 61,885 Revenue from contracts with customers 529,743 703,534 41,161 49,653 (78,110 ) 1,245,981 Other revenues 2,218 3,106 27,429 1,675 (27,337 ) 7,091 Total revenues $ 531,961 $ 706,640 $ 68,590 $ 51,328 $ (105,447 ) $ 1,253,072 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 49,653 $ (23,761 ) $ 25,892 Services transferred over time 529,743 703,534 41,161 — (54,349 ) 1,220,089 Revenue from contracts with customers $ 529,743 $ 703,534 $ 41,161 $ 49,653 $ (78,110 ) $ 1,245,981 |
Business Segment Information (T
Business Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting Information, Additional Information [Abstract] | |
Segment Reporting | Segment information and Corporate and Other included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands): Three Months Ended September 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric Utilities $ 179,527 $ 231 $ 5,032 $ — $ 184,790 $ 21,578 Gas Utilities 130,390 1,011 275 — 131,676 (13,277 ) Power Generation (b) 1,437 348 13,048 8,770 23,603 6,691 Mining 8,809 226 7,942 324 17,301 3,572 Corporate and Other — — — — — (757 ) Inter-company eliminations — — (26,297 ) (9,094 ) (35,391 ) — Total $ 320,163 $ 1,816 $ — $ — $ 321,979 $ 17,807 Under our modified retrospective adoption of ASU 2014-09, revenues for the three and nine months ended September 30, 2017 are not presented by contract type. Three Months Ended September 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric Utilities $ 181,238 $ 2,333 $ 27,324 Gas Utilities 142,821 73 (4,329 ) Power Generation (b) 1,810 21,117 6,155 Mining 9,742 7,751 3,477 Corporate and Other — — (3,664 ) Inter-company eliminations — (31,274 ) — Total $ 335,611 $ — $ 28,963 Nine Months Ended September 30, 2018 External Operating Revenue Inter-company Operating Revenue Total Revenues Net income (loss) from continuing operations Contract Customers Other Revenues Contract Customers Other Revenues Segment: Electric Utilities $ 513,270 $ 2,218 $ 16,473 $ — $ 531,961 $ 63,313 Gas Utilities (a) 702,532 3,106 1,002 — 706,640 93,182 Power Generation (b) 4,287 1,066 36,874 26,363 68,590 17,319 Mining 25,892 701 23,761 974 51,328 9,561 Corporate and Other — — — — — (5,877 ) Inter-company eliminations — — (78,110 ) (27,337 ) (105,447 ) — Total $ 1,245,981 $ 7,091 $ — $ — $ 1,253,072 $ 177,498 Nine Months Ended September 30, 2017 External Operating Revenue Inter-company Operating Revenue Net income (loss) from continuing operations Segment: Electric Utilities $ 518,925 $ 9,123 $ 68,386 Gas Utilities 674,161 90 41,409 Power Generation (b) 5,382 62,907 18,017 Mining 26,500 22,485 9,048 Corporate and Other (c) — — (6,994 ) Inter-company eliminations — (94,605 ) — Total $ 1,224,968 $ — $ 129,866 ___________ (a) Net income from continuing operations available for common stock for the nine months ended September 30, 2018 included a $49 million tax benefit resulting from legal entity restructuring. See Note 19 Income Taxes of the Notes to Condensed Consolidated Financial Statements for more information. (b) Net income from continuing operations available for common stock for the three and nine months ended September 30, 2018 and September 30, 2017 reflects net income attributable to noncontrolling interests of $4.0 million and $10.4 million , and $3.9 million and $10.6 million , respectively. (c) Net income (loss) from continuing operations available for common stock for the nine months ended September 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. |
Reconciliation of Assets from Segment to Consolidated | Segment information and Corporate and Other 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, 2018 December 31, 2017 September 30, 2017 Segment: Electric Utilities (a) $ 2,853,414 $ 2,906,275 $ 2,911,919 Gas Utilities 3,433,316 3,426,466 3,288,104 Power Generation (a) 122,428 60,852 64,357 Mining 72,602 65,455 66,700 Corporate and Other 177,324 115,612 115,330 Discontinued operations 2,854 84,242 117,338 Total assets $ 6,661,938 $ 6,658,902 $ 6,563,748 __________ (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 as a capital lease. |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 43,108 $ 31,381 $ (386 ) $ 74,103 Gas Utilities 48,638 24,768 (2,188 ) 71,218 Power Generation 1,696 — — 1,696 Mining 3,749 — — 3,749 Corporate 2,030 — — 2,030 Total $ 99,221 $ 56,149 $ (2,574 ) $ 152,796 Accounts Unbilled Less Allowance for Accounts December 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 Accounts Unbilled Less Allowance for Accounts September 30, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 42,716 $ 29,762 $ (494 ) $ 71,984 Gas Utilities 49,842 24,516 (1,190 ) 73,168 Power Generation 1,010 — — 1,010 Mining 3,534 — — 3,534 Corporate 629 — — 629 Total $ 97,731 $ 54,278 $ (1,684 ) $ 150,325 |
Regulatory Accounting (Tables)
Regulatory Accounting (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 29,976 $ 20,187 $ 20,559 Deferred gas cost adjustments (a) 720 31,844 12,833 Gas price derivatives (a) 6,192 11,935 11,297 Deferred taxes on AFUDC (b) 7,804 7,847 15,645 Employee benefit plans (c) 106,734 109,235 105,671 Environmental (a) 972 1,031 1,051 Asset retirement obligations (a) 526 517 514 Loss on reacquired debt (a) 21,431 20,667 21,067 Renewable energy standard adjustment (a) 1,131 1,088 1,956 Deferred taxes on flow through accounting (c) (e) 29,342 26,978 41,900 Decommissioning costs (b) 11,052 13,287 13,989 Gas supply contract termination (a) 15,745 20,001 21,402 Other regulatory assets (a) 28,725 32,837 32,710 Total regulatory assets 260,350 297,454 300,594 Less current regulatory assets (48,302 ) (81,016 ) (61,023 ) Regulatory assets, non-current $ 212,048 $ 216,438 $ 239,571 Regulatory liabilities Deferred energy and gas costs (a) $ 15,980 $ 3,427 $ 3,780 Employee benefit plan costs and related deferred taxes (c) (e) 39,332 40,629 66,620 Cost of removal (a) 146,177 130,932 125,360 Excess deferred income taxes (c) (d) 316,625 301,553 52 TCJA revenue reserve 20,592 — — Other regulatory liabilities (c) 11,582 8,585 9,419 Total regulatory liabilities 550,288 485,126 205,231 Less current regulatory liabilities (41,442 ) (6,832 ) (7,042 ) Regulatory liabilities, non-current $ 508,846 $ 478,294 $ 198,189 __________ (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) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of September 30, 2018 and December 31, 2017, all of the liability was classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets. (e) The variance to the prior periods is primarily due to the decrease in federal income tax from 35% to 21% as a result of the TCJA. |
Schedule of TCJA (Federal Tax Reform) Benefits Passed On To Customers By State | A list of states where benefits to customers of federal tax reform have been approved is summarized below. State Approximate 2018 Benefit for Customers Start Date for Customer Benefits Arkansas $ 9.7 million October 2018 Colorado $ 10.8 million July 2018 Iowa $ 2.4 million June 2018 Kansas $ 1.9 million April 2018 Nebraska $ 3.8 million July 2018 South Dakota $ 7.7 million October 2018 |
Materials, Supplies and Fuel (T
Materials, Supplies and Fuel (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 December 31, 2017 September 30, 2017 Materials and supplies $ 73,777 $ 69,732 $ 70,284 Fuel - Electric Utilities 2,750 2,962 2,993 Natural gas in storage held for distribution 46,091 40,589 49,589 Total materials, supplies and fuel $ 122,618 $ 113,283 $ 122,866 |
Investments (Tables)
Investments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Long-term Investments [Abstract] | |
Investments | The following table presents the carrying value of our investments (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Cost method investment $ 28,134 $ — $ — Cash surrender value of life insurance contracts 13,068 13,090 12,947 Total investments $ 41,202 $ 13,090 $ 12,947 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 was as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Net income available for common stock $ 16,950 $ 27,663 $ 171,871 $ 126,381 Weighted average shares - basic 53,364 53,243 53,346 53,208 Dilutive effect of: Equity Units (a) 1,344 2,015 1,060 1,872 Equity compensation 111 174 102 174 Weighted average shares - diluted 54,819 55,432 54,508 55,254 __________ (a) Calculated using the treasury stock method. |
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, 2018 2017 2018 2017 Equity compensation 12 — 15 — Anti-dilutive shares 12 — 15 — |
Notes Payable, Current Maturi_2
Notes Payable, Current Maturities and Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 December 31, 2017 September 30, 2017 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 15,203 $ — $ 26,848 $ — $ 25,391 CP Program 112,100 — 211,300 — 225,170 — Total $ 112,100 $ 15,203 $ 211,300 $ 26,848 $ 225,170 $ 25,391 |
Schedule of Credit Facility Covenants | Our Revolving Credit Facility and term loans require compliance with the following financial covenant at the end of each quarter: As of September 30, 2018 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 61.4% Less than 65% |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Statement of Stockholders' Equity [Abstract] | |
Schedule of Stockholders Equity | A summary of the changes in equity is as follows: Nine Months Ended September 30, 2018 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2017 $ 1,708,974 $ 111,232 $ 1,820,206 Net income (loss) 171,871 10,447 182,318 Other comprehensive income 3,481 — 3,481 Dividends on common stock (76,309 ) — (76,309 ) Share-based compensation 4,871 — 4,871 Dividend reinvestment and stock purchase plan 220 — 220 Other stock transactions 147 — 147 Distribution to noncontrolling interest — (13,755 ) (13,755 ) Balance at September 30, 2018 $ 1,813,255 $ 107,924 $ 1,921,179 Nine Months Ended September 30, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 126,381 10,567 136,948 Other comprehensive income 2,317 — 2,317 Dividends on common stock (71,334 ) — (71,334 ) Share-based compensation 5,853 — 5,853 Dividend reinvestment and stock purchase plan 2,300 — 2,300 Redeemable noncontrolling interest (886 ) — (886 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (180 ) — (180 ) Distribution to noncontrolling interest — (12,884 ) (12,884 ) Balance at September 30, 2017 $ 1,682,804 $ 113,178 $ 1,795,982 |
Risk Management Activities (Tab
Risk Management Activities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Contract or notional amounts and terms of marketing activities and derivative commodity instruments | 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, 2018 December 31, 2017 September 30, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 5,300,000 27 8,330,000 36 10,250,000 39 Natural gas options purchased, net 9,670,000 16 3,540,000 14 7,360,000 17 Natural gas basis swaps purchased 5,140,000 27 8,060,000 36 9,170,000 39 Natural gas over-the-counter swaps, net (b) 4,370,000 20 3,820,000 29 4,600,000 20 Natural gas physical contracts, net (c) 19,539,851 33 12,826,605 35 21,071,714 38 __________ (a) Term reflects the maximum forward period hedged. (b) As of September 30, 2018 , 2,236,000 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (c) Volumes exclude contracts that qualify for the normal purchase, normal sales exception. |
Derivative Instruments, Gain (Loss) | The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended September 30, 2018 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (712 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (18 ) Fuel, purchased power and cost of natural gas sold — Total $ (730 ) $ — Three Months Ended September 30, 2017 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (713 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 295 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (34 ) Fuel, purchased power and cost of natural gas sold — Total $ (452 ) $ — Nine Months Ended September 30, 2018 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (2,138 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (802 ) Fuel, purchased power and cost of natural gas sold — Total $ (2,940 ) $ — Nine Months Ended September 30, 2017 Derivatives in Cash Flow Hedging Relationships 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 Interest expense $ (2,228 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 954 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (20 ) Fuel, purchased power and cost of natural gas sold — Total $ (1,294 ) $ — The following tables summarize the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three and nine months ended September 30, 2018 and 2017 . The amounts included in the tables below exclude gains and losses arising from ineffectiveness because these amounts, if any, are immediately recognized in the Condensed Consolidated Statements of Income as incurred. Three Months Ended September 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ 30 $ (254 ) Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 712 713 Forward commodity contracts 18 (261 ) Total other comprehensive income (loss) from hedging $ 760 $ 198 Nine Months Ended September 30, 2018 2017 (in thousands) Increase (decrease) in fair value: Forward commodity contracts $ (219 ) $ 1,197 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,138 2,228 Forward commodity contracts 802 (934 ) Total other comprehensive income (loss) from hedging $ 2,721 $ 2,491 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017 (in thousands). Note that this presentation does not reflect gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Three Months Ended September 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ (53 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold (96 ) (322 ) $ (96 ) $ (375 ) Nine Months Ended September 30, 2018 2017 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ 90 Commodity derivatives Fuel, purchased power and cost of natural gas sold 929 (1,822 ) $ 929 $ (1,732 ) As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our utilities were $6.2 million , $12 million and $11 million at September 30, 2018 , December 31, 2017 and September 30, 2017 , respectively. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 present 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, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 5,882 $ — $ (4,469 ) $ 1,413 Total $ — $ 5,882 $ — $ (4,469 ) $ 1,413 Liabilities: Commodity derivatives — Utilities $ — $ 10,033 $ — $ (8,777 ) $ 1,256 Total $ — $ 10,033 $ — $ (8,777 ) $ 1,256 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives — Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of September 30, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Utilities $ — $ 2,880 $ — $ (2,448 ) $ 432 Total $ — $ 2,880 $ — $ (2,448 ) $ 432 Liabilities: Commodity derivatives — Utilities $ — $ 12,647 $ — $ (11,125 ) $ 1,522 Total $ — $ 12,647 $ — $ (11,125 ) $ 1,522 |
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, 2018 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 142 $ — Commodity derivatives Other assets, non-current 21 — Commodity derivatives Derivative liabilities — current — 273 Commodity derivatives Other deferred credits and other liabilities — 10 Total derivatives designated as hedges $ 163 $ 283 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,250 $ — Commodity derivatives Derivative liabilities — current — 881 Commodity derivatives Other deferred credits and other liabilities — 92 Total derivatives not designated as hedges $ 1,250 $ 973 As of December 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative liabilities — current $ — $ 817 Commodity derivatives Other deferred credits and other liabilities — 67 Total derivatives designated as hedges $ — $ 884 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 304 $ — Commodity derivatives Derivative liabilities — current — 1,264 Commodity derivatives Other deferred credits and other liabilities — 111 Total derivatives not designated as hedges $ 304 $ 1,375 As of September 30, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2 $ — Commodity derivatives Current assets held for sale 225 — Commodity derivatives Derivative liabilities — current — 422 Commodity derivatives Current liabilities held for sale — 89 Commodity derivatives Other deferred credits and other liabilities — 49 Commodity derivatives Noncurrent liabilities held for sale — 10 Total derivatives designated as hedges $ 227 $ 570 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 430 $ — Commodity derivatives Derivative liabilities — current — 1,036 Commodity derivatives Other deferred credits and other liabilities — 15 Commodity derivatives Noncurrent liabilities held for sale — 15 Total derivatives not designated as hedges $ 430 $ 1,066 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 12 , were as follows (in thousands) as of: September 30, 2018 December 31, 2017 September 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 10,001 $ 10,001 $ 15,420 $ 15,420 $ 13,449 $ 13,449 Restricted cash (a) $ 3,241 $ 3,241 $ 2,820 $ 2,820 $ 2,683 $ 2,683 Notes payable (b) $ 112,100 $ 112,100 $ 211,300 $ 211,300 $ 225,170 $ 225,170 Long-term debt, including current maturities (c) (d) $ 3,207,132 $ 3,289,770 $ 3,115,143 $ 3,350,544 $ 3,115,607 $ 3,362,971 __________ (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) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) 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. (d) Carrying amount of long-term debt is net of deferred financing costs. |
Other Comprehensive Income (L_2
Other Comprehensive Income (Loss) (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | |
Reclassification Out of Accumulated Other Comprehensive Income (Loss) | The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Condensed Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three Months Ended Nine Months Ended September 30, 2018 September 30, 2017 September 30, 2018 September 30, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (712 ) $ (713 ) $ (2,138 ) $ (2,228 ) Commodity contracts Net (loss) from discontinued operations — 295 — 954 Commodity contracts Fuel, purchased power and cost of natural gas sold (18 ) (34 ) (802 ) (20 ) (730 ) (452 ) (2,940 ) (1,294 ) Income tax Income tax benefit (expense) 149 154 643 435 Total reclassification adjustments related to cash flow hedges, net of tax $ (581 ) $ (298 ) $ (2,297 ) $ (859 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 44 $ 49 $ 133 $ 146 Actuarial gain (loss) Operations and maintenance (621 ) (414 ) (1,865 ) (1,242 ) (577 ) (365 ) (1,732 ) (1,096 ) Income tax Income tax benefit (expense) 128 128 380 393 Total reclassification adjustments related to defined benefit plans, net of tax $ (449 ) $ (237 ) $ (1,352 ) $ (703 ) Total reclassifications $ (1,030 ) $ (535 ) $ (3,649 ) $ (1,562 ) |
Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — (168 ) — (168 ) Amounts reclassified from AOCI 1,682 615 1,352 3,649 Reclassifications of certain tax effects from AOCI 15 — 3 18 Ending Balance September 30, 2018 $ (17,884 ) $ (71 ) $ (19,748 ) $ (37,703 ) Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 755 — 755 Amounts reclassified from AOCI 1,449 (590 ) 703 1,562 Ending Balance September 30, 2017 $ (16,660 ) $ (68 ) $ (15,838 ) $ (32,566 ) |
Supplemental Disclosure of Ca_2
Supplemental Disclosure of Cash Flow Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Nine Months Ended September 30, 2018 September 30, 2017 (in thousands) Non-cash investing and financing activities — Property, plant and equipment acquired with accrued liabilities $ 49,631 $ 33,409 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 155 $ 1,362 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (104,035 ) $ (102,008 ) Income taxes (paid) refunded $ (14,842 ) $ 1 |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Defined Benefit Plan [Abstract] | |
Schedule of Net Benefit Costs | The components of net periodic benefit cost for the Defined Benefit Pension Plan were as follows (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Service cost $ 1,708 $ 1,759 $ 5,125 $ 5,276 Interest cost 3,867 3,880 11,602 11,640 Expected return on plan assets (6,185 ) (6,130 ) (18,555 ) (18,388 ) Prior service cost 15 15 44 44 Net loss (gain) 2,158 1,002 6,473 3,005 Net periodic benefit cost $ 1,563 $ 526 $ 4,689 $ 1,577 Defined Benefit Postretirement Healthcare Plans 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, 2018 2017 2018 2017 Service cost $ 573 $ 575 $ 1,718 $ 1,725 Interest cost 521 533 1,563 1,600 Expected return on plan assets (57 ) (79 ) (170 ) (237 ) Prior service cost (benefit) (99 ) (109 ) (297 ) (327 ) Net loss (gain) 54 125 162 375 Net periodic benefit cost $ 992 $ 1,045 $ 2,976 $ 3,136 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, 2018 2017 2018 2017 Service cost $ 632 $ 612 $ 1,347 $ 2,048 Interest cost 293 319 878 957 Prior service cost — — 1 1 Net loss (gain) 250 251 750 751 Net periodic benefit cost $ 1,175 $ 1,182 $ 2,976 $ 3,757 |
Schedule of Defined Benefit Plans Contributions | Contributions made in 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Anticipated for 2018 Anticipated for 2019 Defined Benefit Pension Plan $ 12,700 $ 12,700 $ — $ 12,700 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,234 $ 3,702 $ 1,234 $ 3,821 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 343 $ 1,029 $ 343 $ 1,623 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts | Held for sale assets and liabilities at September 30, 2017 are classified as current and non-current (in thousands): September 30, 2018 December 31, 2017 September 30, 2017 Other current assets $ 75 $ 10,360 $ 8,457 Derivative assets, current and noncurrent — — 225 Deferred income tax assets, noncurrent, net — 16,966 12,571 Property, plant and equipment, net 2,779 56,916 96,085 Other current liabilities (2,138 ) (18,966 ) (7,597 ) Derivative liabilities, current and noncurrent — — (114 ) Deferred income tax liabilities, noncurrent, net (400 ) — — Other noncurrent liabilities — (22,808 ) (23,319 ) Net assets (liabilities) $ 316 $ 42,468 $ 86,308 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation | The effective tax rate differs from the federal statutory rate as follows: Three Months Ended September 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) (a) (6.3 ) (3.4 ) Percentage depletion in excess of cost (0.5 ) (0.9 ) Accounting for uncertain tax positions adjustment — (0.6 ) Noncontrolling interest (b) (1.3 ) (3.0 ) Tax credits (c) (5.3 ) (1.6 ) Effective tax rate adjustment (d) — 3.9 Flow-through adjustments (1.5 ) (1.6 ) TCJA change in estimate (e) 17.6 — AFUDC equity (0.1 ) — Other tax differences 1.9 1.3 25.5 % 29.1 % __________ (a) Adjustment to the deferred state rate and reduced state tax expense for the quarter. (b) The adjustment reflects the noncontrolling interest attributable to the sale in April 2016 of 49.9% of the membership interests of COIPP LLC. (c) The tax credits are due to the production tax credits for the Peak View wind farm. (d) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. (e) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the three months ended September 30, 2018, we recorded an additional $5.3 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. Nine Months Ended September 30, Tax (benefit) expense 2018 2017 Federal statutory rate 21.0 % 35.0 % State income tax (net of federal tax effect) 0.4 0.3 Percentage depletion in excess of cost (0.4 ) (0.6 ) Accounting for uncertain tax positions adjustment — (0.2 ) Noncontrolling interest (1.1 ) (1.9 ) IRC 172(f) carryback claim (a) — (1.0 ) Tax credits (b) (2.6 ) (1.6 ) Effective tax rate adjustment — 0.3 Flow-through adjustments (0.8 ) (1.2 ) TCJA change in estimate (c) 4.3 — AFUDC equity (0.1 ) — Jurisdictional simplification project (d) (28.1 ) — Other tax differences 0.7 0.3 (6.7 )% 29.4 % __________ (a) During the first quarter of 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company’s accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (b) The tax credits are due to the production tax credits for the Peak View wind farm. (c) The TCJA was signed into law on December 22, 2017. In accordance with ASC 740, net deferred tax assets and liabilities were revalued as of December 31, 2017 due to the reduction in the federal income tax rate from 35% to 21%. During the nine months ended September 30, 2018, we recorded an additional $7.5 million of tax expense associated with changes in the prior estimated impacts of tax reform on deferred income taxes. (d) Tax benefit from legal restructuring associated with amortizable goodwill as part of jurisdictional simplification. |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 December 31, 2017 September 30, 2017 Accrued employee compensation, benefits and withholdings $ 57,600 $ 52,467 $ 52,841 Accrued property taxes 37,660 42,029 36,993 Customer deposits and prepayments 42,002 44,420 41,012 Accrued interest and contract adjustment payments 31,139 33,822 30,977 CIAC current portion 1,552 1,552 1,575 Other (none of which is individually significant) 31,400 45,172 43,381 Total accrued liabilities $ 201,353 $ 219,462 $ 206,779 |
Management's Statement (Details
Management's Statement (Details) | Sep. 30, 2018USD ($) |
Accounting Standards Update 2014-09 | |
Disaggregation of Revenue [Line Items] | |
Amount of cumulative adoption adjustment to the opening balance of Retained Earnings | $ 0 |
Revenue_ Disaggregation of Reve
Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | $ 320,163 | $ 1,245,981 | ||
Total revenues | 321,979 | $ 335,611 | 1,253,072 | $ 1,224,968 |
Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 8,810 | 25,892 | ||
Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 311,353 | 1,220,089 | ||
Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 1,816 | 7,091 | ||
Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 254,418 | 1,041,190 | ||
Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 29,812 | 99,783 | ||
Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 9,693 | 29,784 | ||
Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 7,850 | 13,339 | ||
Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 18,390 | 61,885 | ||
Inter-company Revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (26,297) | (78,110) | ||
Total revenues | (35,391) | $ (31,274) | (105,447) | $ (94,605) |
Inter-company Revenues | Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (7,941) | (23,761) | ||
Inter-company Revenues | Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (18,356) | (54,349) | ||
Inter-company Revenues | Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | (9,094) | (27,337) | ||
Inter-company Revenues | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (7,941) | (23,761) | ||
Inter-company Revenues | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (267) | (977) | ||
Inter-company Revenues | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (13,047) | (36,874) | ||
Inter-company Revenues | Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (1,349) | (5,531) | ||
Inter-company Revenues | Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | (3,693) | (10,967) | ||
Electric Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 184,559 | 529,743 | ||
Total revenues | 184,790 | 531,961 | ||
Electric Utilities | Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Electric Utilities | Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 184,559 | 529,743 | ||
Electric Utilities | Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 231 | 2,218 | ||
Electric Utilities | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 157,049 | 449,482 | ||
Electric Utilities | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Electric Utilities | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 8,255 | 25,497 | ||
Electric Utilities | Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 9,059 | 18,142 | ||
Electric Utilities | Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 10,196 | 36,622 | ||
Gas Utilities | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 130,665 | 703,534 | ||
Total revenues | 131,676 | 706,640 | ||
Gas Utilities | Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Gas Utilities | Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 130,665 | 703,534 | ||
Gas Utilities | Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 1,011 | 3,106 | ||
Gas Utilities | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 88,559 | 565,816 | ||
Gas Utilities | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 30,079 | 100,760 | ||
Gas Utilities | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Gas Utilities | Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 140 | 728 | ||
Gas Utilities | Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 11,887 | 36,230 | ||
Power Generation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 14,485 | 41,161 | ||
Total revenues | 23,603 | 68,590 | ||
Power Generation | Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Power Generation | Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 14,485 | 41,161 | ||
Power Generation | Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 9,118 | 27,429 | ||
Power Generation | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Power Generation | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Power Generation | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 14,485 | 41,161 | ||
Power Generation | Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Power Generation | Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Mining | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 16,751 | 49,653 | ||
Total revenues | 17,301 | 51,328 | ||
Mining | Services transferred at a point in time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 16,751 | 49,653 | ||
Mining | Services transferred over time | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Mining | Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 550 | 1,675 | ||
Mining | Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 16,751 | 49,653 | ||
Mining | Transportation | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Mining | Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Mining | Market - off-system sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 0 | 0 | ||
Mining | Transmission/Other | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | $ 0 | $ 0 |
Revenue_ Revenue Not in Scope o
Revenue: Revenue Not in Scope of ASC 606 (Details) | 9 Months Ended |
Sep. 30, 2018 | |
Sale Agreement Between Colorado IPP and Affiliate Colorado Electric | |
Disaggregation of Revenue [Line Items] | |
Long-term Purchase Commitment, Period | 20 years |
Revenue_ Significant Judgements
Revenue: Significant Judgements and Estimates (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018USD ($)State | Sep. 30, 2018USD ($)State | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | |
Number of States That Have Received State Utility Commission Approvals to Provide the Benefits of Federal Tax Reform to Utility Customers | State | 6 | 6 | ||
Regulatory Liabilities | $ 550,288 | $ 550,288 | $ 485,126 | $ 205,231 |
Revenue refunded to customers as a result of the TCJA tax benefits | 7,900 | |||
TCJA Revenue Reserve Subject to Refund | ||||
Estimated and recorded revenue reduction from TCJA tax benefits | 6,000 | 29,000 | ||
Regulatory Liabilities | $ 20,592 | $ 20,592 | $ 0 | $ 0 |
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, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Segment Reporting Information | ||||
Revenue from contracts with customers | $ 320,163 | $ 1,245,981 | ||
Revenues | 321,979 | $ 335,611 | 1,253,072 | $ 1,224,968 |
Net income (loss) from continuing operations | 17,807 | 28,963 | 177,498 | 129,866 |
Deferred income taxes | (14,396) | 65,536 | ||
Net income attributable to noncontrolling interests | 3,994 | 3,935 | 10,447 | 10,674 |
Net tax benefit | 1,400 | |||
Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 1,816 | 7,091 | ||
Other Restructuring | ||||
Segment Reporting Information | ||||
Deferred income taxes | 49,000 | |||
Inter-company Revenues | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | (26,297) | (78,110) | ||
Revenues | (35,391) | (31,274) | (105,447) | (94,605) |
Net income (loss) from continuing operations | 0 | 0 | 0 | 0 |
Inter-company Revenues | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | (9,094) | (27,337) | ||
Corporate | ||||
Segment Reporting Information | ||||
Net income (loss) from continuing operations | (757) | (3,664) | (5,877) | (6,994) |
Consolidation, Eliminations | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 0 | 0 | ||
Revenues | 0 | 0 | ||
Consolidation, Eliminations | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 0 | 0 | ||
Electric Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 184,559 | 529,743 | ||
Revenues | 184,790 | 531,961 | ||
Net income (loss) from continuing operations | 21,578 | 27,324 | 63,313 | 68,386 |
Electric Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 231 | 2,218 | ||
Gas Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 130,665 | 703,534 | ||
Revenues | 131,676 | 706,640 | ||
Net income (loss) from continuing operations | (13,277) | (4,329) | 93,182 | 41,409 |
Gas Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 1,011 | 3,106 | ||
Power Generation | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 14,485 | 41,161 | ||
Revenues | 23,603 | 68,590 | ||
Net income (loss) from continuing operations | 6,691 | 6,155 | 17,319 | 18,017 |
Net income attributable to noncontrolling interests | 4,000 | 3,900 | 10,400 | 10,600 |
Power Generation | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 9,118 | 27,429 | ||
Mining | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 16,751 | 49,653 | ||
Revenues | 17,301 | 51,328 | ||
Net income (loss) from continuing operations | 3,572 | 3,477 | 9,561 | 9,048 |
Mining | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 550 | 1,675 | ||
External Operating Revenue | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 320,163 | 1,245,981 | ||
External Operating Revenue | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 1,816 | 7,091 | ||
External Operating Revenue | Electric Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 179,527 | 513,270 | ||
Revenues | 181,238 | 518,925 | ||
External Operating Revenue | Electric Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 231 | 2,218 | ||
External Operating Revenue | Gas Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 130,390 | 702,532 | ||
Revenues | 142,821 | 674,161 | ||
External Operating Revenue | Gas Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 1,011 | 3,106 | ||
External Operating Revenue | Power Generation | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 1,437 | 4,287 | ||
Revenues | 1,810 | 5,382 | ||
External Operating Revenue | Power Generation | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 348 | 1,066 | ||
External Operating Revenue | Mining | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 8,809 | 25,892 | ||
Revenues | 9,742 | 26,500 | ||
External Operating Revenue | Mining | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 226 | 701 | ||
Inter-company Operating Revenue | Electric Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 5,032 | 16,473 | ||
Revenues | 2,333 | 9,123 | ||
Inter-company Operating Revenue | Electric Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 0 | 0 | ||
Inter-company Operating Revenue | Gas Utilities | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 275 | 1,002 | ||
Revenues | 73 | 90 | ||
Inter-company Operating Revenue | Gas Utilities | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 0 | 0 | ||
Inter-company Operating Revenue | Power Generation | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 13,048 | 36,874 | ||
Revenues | 21,117 | 62,907 | ||
Inter-company Operating Revenue | Power Generation | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | 8,770 | 26,363 | ||
Inter-company Operating Revenue | Mining | ||||
Segment Reporting Information | ||||
Revenue from contracts with customers | 7,942 | 23,761 | ||
Revenues | $ 7,751 | $ 22,485 | ||
Inter-company Operating Revenue | Mining | Other Revenues | ||||
Segment Reporting Information | ||||
Revenues | $ 324 | $ 974 |
Business Segment Information_ S
Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | $ 6,661,938 | $ 6,658,902 | $ 6,563,748 |
Discontinued Operations, Held-for-sale | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | 2,854 | 84,242 | 117,338 |
Corporate | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | 177,324 | 115,612 | 115,330 |
Electric Utilities | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | 2,853,414 | 2,906,275 | 2,911,919 |
Gas Utilities | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | 3,433,316 | 3,426,466 | 3,288,104 |
Power Generation | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | 122,428 | 60,852 | 64,357 |
Mining | |||
Segment Reporting, Asset Reconciling Item [Line Items] | |||
Assets | $ 72,602 | $ 65,455 | $ 66,700 |
Accounts Receivable (Details)
Accounts Receivable (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | $ 99,221 | $ 126,060 | $ 97,731 |
Unbilled Receivables, Current | 56,149 | 125,351 | 54,278 |
Allowance for Doubtful Accounts | (2,574) | (3,081) | (1,684) |
Accounts receivable, net | 152,796 | 248,330 | 150,325 |
Corporate | |||
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | 2,030 | 1,457 | 629 |
Unbilled Receivables, Current | 0 | 0 | 0 |
Allowance for Doubtful Accounts | 0 | 0 | 0 |
Accounts receivable, net | 2,030 | 1,457 | 629 |
Electric Utilities | |||
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | 43,108 | 39,347 | 42,716 |
Unbilled Receivables, Current | 31,381 | 36,384 | 29,762 |
Allowance for Doubtful Accounts | (386) | (586) | (494) |
Accounts receivable, net | 74,103 | 75,145 | 71,984 |
Gas Utilities | |||
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | 48,638 | 81,256 | 49,842 |
Unbilled Receivables, Current | 24,768 | 88,967 | 24,516 |
Allowance for Doubtful Accounts | (2,188) | (2,495) | (1,190) |
Accounts receivable, net | 71,218 | 167,728 | 73,168 |
Power Generation | |||
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | 1,696 | 1,196 | 1,010 |
Unbilled Receivables, Current | 0 | 0 | 0 |
Allowance for Doubtful Accounts | 0 | 0 | 0 |
Accounts receivable, net | 1,696 | 1,196 | 1,010 |
Mining | |||
Accounts Receivable [Line Items] | |||
Accounts Receivable, Trade | 3,749 | 2,804 | 3,534 |
Unbilled Receivables, Current | 0 | 0 | 0 |
Allowance for Doubtful Accounts | 0 | 0 | 0 |
Accounts receivable, net | $ 3,749 | $ 2,804 | $ 3,534 |
Regulatory Accounting (Details)
Regulatory Accounting (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Regulatory assets | |||
Regulatory assets | $ 260,350 | $ 297,454 | $ 300,594 |
Less current regulatory assets | (48,302) | (81,016) | (61,023) |
Regulatory assets, non-current | 212,048 | 216,438 | 239,571 |
Regulatory liabilities | |||
Regulatory liabilities | 550,288 | 485,126 | 205,231 |
Less current regulatory liabilities | (41,442) | (6,832) | (7,042) |
Regulatory liabilities, non-current | 508,846 | 478,294 | 198,189 |
Deferred energy and gas costs | |||
Regulatory liabilities | |||
Regulatory liabilities | 15,980 | 3,427 | 3,780 |
Employee benefit plans | |||
Regulatory liabilities | |||
Regulatory liabilities | 39,332 | 40,629 | 66,620 |
Cost of removal | |||
Regulatory liabilities | |||
Regulatory liabilities | 146,177 | 130,932 | 125,360 |
Excess deferred income taxes | |||
Regulatory liabilities | |||
Regulatory liabilities | 316,625 | 301,553 | 52 |
TCJA revenue reduction | |||
Regulatory liabilities | |||
Regulatory liabilities | 20,592 | 0 | 0 |
Other regulatory liabilities | |||
Regulatory liabilities | |||
Regulatory liabilities | 11,582 | 8,585 | 9,419 |
Deferred energy and gas costs | |||
Regulatory assets | |||
Regulatory assets | 29,976 | 20,187 | 20,559 |
Deferred gas cost adjustments | |||
Regulatory assets | |||
Regulatory assets | 720 | 31,844 | 12,833 |
Gas price derivatives | |||
Regulatory assets | |||
Regulatory assets | 6,192 | 11,935 | 11,297 |
Deferred taxes on AFUDC | |||
Regulatory assets | |||
Regulatory assets | 7,804 | 7,847 | 15,645 |
Employee benefit plans | |||
Regulatory assets | |||
Regulatory assets | 106,734 | 109,235 | 105,671 |
Environmental | |||
Regulatory assets | |||
Regulatory assets | 972 | 1,031 | 1,051 |
Asset retirement obligations | |||
Regulatory assets | |||
Regulatory assets | 526 | 517 | 514 |
Loss on reacquired debt | |||
Regulatory assets | |||
Regulatory assets | 21,431 | 20,667 | 21,067 |
Renewable energy standard adjustment | |||
Regulatory assets | |||
Regulatory assets | 1,131 | 1,088 | 1,956 |
Deferred taxes on flow through accounting | |||
Regulatory assets | |||
Regulatory assets | 29,342 | 26,978 | 41,900 |
Decommissioning costs | |||
Regulatory assets | |||
Regulatory assets | 11,052 | 13,287 | 13,989 |
Gas supply contract termination | |||
Regulatory assets | |||
Regulatory assets | 15,745 | 20,001 | 21,402 |
Other regulatory assets | |||
Regulatory assets | |||
Regulatory assets | $ 28,725 | $ 32,837 | $ 32,710 |
Regulatory Accounting_ TCJA Rev
Regulatory Accounting: TCJA Revenue Reserve (Details) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018USD ($)State | Sep. 30, 2018USD ($)State | |
Number of States That Have Received State Utility Commission Approvals to Provide the Benefits of Federal Tax Reform to Utility Customers | State | 6 | 6 |
Revenue refunded to customers as a result of the TCJA tax benefits | $ 7.9 | |
Arkansas Public Service Commission (APSC) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 9.7 | |
Colorado Public Utilities Commission (CPUC) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 10.8 | |
Iowa Utilities Board (IUB) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 2.4 | |
Kansas Public Utilities Commission (KPUC) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 1.9 | |
Nebraska Public Service Commission (NPSC) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 3.8 | |
South Dakota Public Utilities Commission (SDPUC) | ||
Estimated and recorded revenue reduction from TCJA tax benefits | 7.7 | |
TCJA Revenue Reserve Subject to Refund | ||
Estimated and recorded revenue reduction from TCJA tax benefits | $ 6 | $ 29 |
Regulatory Accounting_ Rate Rev
Regulatory Accounting: Rate Review (Details) - USD ($) $ in Thousands | Oct. 31, 2018 | Oct. 05, 2018 | Sep. 05, 2018 | Jul. 16, 2018 | Jun. 19, 2018 | Jun. 01, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Liabilities | $ 550,288 | $ 485,126 | $ 205,231 | ||||||
Other regulatory liabilities | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Liabilities | 11,582 | $ 8,585 | $ 9,419 | ||||||
Colorado Public Utilities Commission (CPUC) | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Estimated and recorded revenue reduction from TCJA tax benefits | 10,800 | ||||||||
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Approved revenue increase | $ 1,100 | ||||||||
Return on equity | 9.90% | ||||||||
Capital structure, equity | 46.63% | ||||||||
Capital structure, debt | 53.37% | ||||||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Approved revenue increase | $ 1,000 | ||||||||
Return on equity | 9.60% | ||||||||
Capital structure, equity | 54.00% | ||||||||
Capital structure, debt | 46.00% | ||||||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Electric | Other regulatory liabilities | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Liabilities | 4,500 | ||||||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Electric | Subsequent Event | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Public Utilities, Aggregate Amount of Customer Credits Through The Power Cost Adjustment Mechanism | $ 7,000 | ||||||||
Public Utilities, Power Purchase Agreement Annual Cost Escalation Percentage Through 2022 | 3.00% | ||||||||
Arkansas Public Service Commission (APSC) | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Estimated and recorded revenue reduction from TCJA tax benefits | 9,700 | ||||||||
Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas | Subsequent Event | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Approved revenue increase | $ 12,000 | ||||||||
Return on equity | 9.61% | ||||||||
Capital structure, equity | 49.10% | ||||||||
Capital structure, debt | 50.90% | ||||||||
Public Utilities, Amount Of Existing Revenue Collected Through Rider Mechanisms Included In New Base Rates | $ 11,000 | ||||||||
Nebraska Public Service Commission (NPSC) | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Estimated and recorded revenue reduction from TCJA tax benefits | $ 3,800 | ||||||||
Nebraska Public Service Commission (NPSC) | Black Hills Gas Distribution - Nebraska | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Approved revenue increase | $ 6,000 | ||||||||
Kansas Corporation Commission | Black Hills Energy, Kansas | Maximum | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Approved revenue increase | $ 8,000 |
Materials, Supplies and Fuel (D
Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Inventory, Net [Abstract] | |||
Materials and supplies | $ 73,777 | $ 69,732 | $ 70,284 |
Fuel - Electric Utilities | 2,750 | 2,962 | 2,993 |
Natural gas in storage held for distribution | 46,091 | 40,589 | 49,589 |
Total materials, supplies and fuel | $ 122,618 | $ 113,283 | $ 122,866 |
Investments (Details)
Investments (Details) - USD ($) $ in Thousands | Feb. 28, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Investment [Line Items] | ||||
Total investments | $ 41,202 | $ 13,090 | $ 12,947 | |
Cost method investment | ||||
Investment [Line Items] | ||||
Assets held for sale contributed in exchange for equity securities in a privately held company | $ 28,000 | |||
Total investments | 28,134 | 0 | 0 | |
Cash surrender value of life insurance contracts | ||||
Investment [Line Items] | ||||
Total investments | $ 13,068 | $ 13,090 | $ 12,947 |
Earnings Per Share_ Earnings Pe
Earnings Per Share: Earnings Per Share Reconciliation (Details) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Earnings Per Share [Abstract] | ||||
Net income available for common stock | $ 16,950 | $ 27,663 | $ 171,871 | $ 126,381 |
Weighted average shares - basic (in shares) | 53,364 | 53,243 | 53,346 | 53,208 |
Dilutive effect of: | ||||
Equity Units (in shares) | 1,344 | 2,015 | 1,060 | 1,872 |
Equity compensation (in shares) | 111 | 174 | 102 | 174 |
Weighted average shares - diluted (in shares) | 54,819 | 55,432 | 54,508 | 55,254 |
Earnings Per Share_ Anti-diluti
Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Anti-dilutive shares | 12 | 0 | 15 | 0 |
Equity compensation | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Anti-dilutive shares | 12 | 0 | 15 | 0 |
Notes Payable, Current Maturi_3
Notes Payable, Current Maturities and Debt: Schedule of Short-term Debt and Narrative (Details) | Jul. 30, 2018USD ($)credit_extension | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) |
Short-term Debt [Line Items] | ||||
Notes payable | $ 112,100,000 | $ 225,170,000 | $ 211,300,000 | |
Letters of Credit | 15,203,000 | 25,391,000 | 26,848,000 | |
Commercial paper, maximum borrowing capacity | 750,000,000 | |||
Net (payments) borrowings of short-term debt | (99,200,000) | 128,570,000 | ||
Commercial Paper | ||||
Short-term Debt [Line Items] | ||||
Notes payable | $ 112,100,000 | 225,170,000 | 211,300,000 | |
Debt term | 397 days | |||
Net (payments) borrowings of short-term debt | $ (99,000,000) | |||
Short-term interest rate | 2.42% | |||
Revolving Credit Facility | ||||
Short-term Debt [Line Items] | ||||
Notes payable | $ 0 | 0 | 0 | |
Letters of Credit | $ 15,203,000 | $ 25,391,000 | $ 26,848,000 | |
Current borrowing capacity | $ 750,000,000 | |||
Number of extension options | credit_extension | 2 | |||
Debt term | 1 year | |||
Maximum borrowing capacity | $ 1,000,000,000 | |||
Commitment fee | 0.175% | |||
Revolving Credit Facility | Base Rate | ||||
Short-term Debt [Line Items] | ||||
Interest rate | 0.125% | |||
Revolving Credit Facility | Eurodollar | ||||
Short-term Debt [Line Items] | ||||
Interest rate | 1.125% | |||
Revolving Credit Facility | Letter of Credit | ||||
Short-term Debt [Line Items] | ||||
Interest rate | 1.125% |
Notes Payable, Current Maturi_4
Notes Payable, Current Maturities and Debt: Debt Covenants (Details) | Sep. 30, 2018 |
Maximum | |
Line of Credit Facility [Line Items] | |
Consolidated Indebtedness to Capitalization Ratio | 0.65 |
Revolving Credit Facility | |
Line of Credit Facility [Line Items] | |
Recourse Leverage Ratio | 61.40% |
Debt instrument, covenant, Leverage Recourse Ratio | 0.65 |
Notes Payable, Current Maturi_5
Notes Payable, Current Maturities and Debt: Current Maturities (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Debt Instrument [Line Items] | |||
Current maturities of long-term debt | $ 255,743 | $ 5,743 | $ 5,743 |
Corporate | Senior Unsecured Notes Due 2019 | |||
Debt Instrument [Line Items] | |||
Current maturities of long-term debt | 250,000 | ||
Corporate | Corporate Term Loan Due June 2021 | |||
Debt Instrument [Line Items] | |||
Current maturities of long-term debt | $ 5,700 |
Notes Payable, Current Maturi_6
Notes Payable, Current Maturities and Debt: Long-Term Debt (Details) - USD ($) $ in Millions | Aug. 17, 2018 | Sep. 30, 2018 |
Remarketable Junior Subordinated Notes Due 2028 | ||
Debt Instrument [Line Items] | ||
Extinguishment of Debt, Amount | $ 299 | |
Remarketable Junior Subordinated Notes Due 2028 | Junior Subordinated Debt | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.579% | |
Corporate Term Loan Due July 2020 | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Gross | $ 300 | |
Corporate Term Loan Due July 2020 | Base Rate | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.00% | |
Corporate Term Loan Due July 2020 | Eurodollar | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.70% | |
Corporate | Corporate Term Loan Due 2033 | ||
Debt Instrument [Line Items] | ||
Proceeds from Issuance of Senior Long-term Debt | $ 400 | |
Debt Instrument, Interest Rate, Stated Percentage | 4.35% |
Equity_ Stockholders Equity Rec
Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Total Equity, beginning balance | $ 1,820,206 | $ 1,730,134 | ||
Net income (loss) | 182,318 | 136,948 | ||
Other comprehensive income | $ 1,060 | $ 375 | 3,481 | 2,317 |
Dividends on common stock | (76,309) | (71,334) | ||
Share-based compensation | 4,871 | 5,853 | ||
Dividend reinvestment and stock purchase plan | 220 | 2,300 | ||
Redeemable noncontrolling interest | (886) | |||
Cumulative effect of ASU 2016-09 implementation | 3,714 | |||
Other stock transactions | 147 | (180) | ||
Distribution to noncontrolling interest | (13,755) | (12,884) | ||
Total Equity, ending balance | 1,921,179 | 1,795,982 | 1,921,179 | 1,795,982 |
Total Stockholders’ Equity | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Total Equity, beginning balance | 1,708,974 | 1,614,639 | ||
Net income (loss) | 171,871 | 126,381 | ||
Other comprehensive income | 3,481 | 2,317 | ||
Dividends on common stock | (76,309) | (71,334) | ||
Share-based compensation | 4,871 | 5,853 | ||
Dividend reinvestment and stock purchase plan | 220 | 2,300 | ||
Redeemable noncontrolling interest | (886) | |||
Cumulative effect of ASU 2016-09 implementation | 3,714 | |||
Other stock transactions | 147 | (180) | ||
Distribution to noncontrolling interest | 0 | 0 | ||
Total Equity, ending balance | 1,813,255 | 1,682,804 | 1,813,255 | 1,682,804 |
Noncontrolling Interest | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Total Equity, beginning balance | 111,232 | 115,495 | ||
Net income (loss) | 10,447 | 10,567 | ||
Other comprehensive income | 0 | 0 | ||
Dividends on common stock | 0 | 0 | ||
Share-based compensation | 0 | 0 | ||
Dividend reinvestment and stock purchase plan | 0 | 0 | ||
Redeemable noncontrolling interest | 0 | |||
Cumulative effect of ASU 2016-09 implementation | 0 | |||
Other stock transactions | 0 | 0 | ||
Distribution to noncontrolling interest | (13,755) | (12,884) | ||
Total Equity, ending balance | $ 107,924 | $ 113,178 | $ 107,924 | $ 113,178 |
Equity_ At-the-Market Equity Of
Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Aug. 04, 2017 | Mar. 18, 2016 |
Statement of Stockholders' Equity [Abstract] | |||
At The Market Equity Offering Program Authorized Aggregate Value | $ 300 | $ 300 | $ 200 |
Equity_ Equity Units Settlement
Equity: Equity Units Settlement (Details) $ / shares in Units, $ in Thousands | Nov. 01, 2018USD ($)$ / sharesshares | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) |
Current maturities of long-term debt | $ | $ 255,743 | $ 5,743 | $ 5,743 | |
Entity Common Stock, Shares Outstanding | shares | 59,974,620 | |||
Senior Unsecured Notes Due 2019 | Corporate | ||||
Current maturities of long-term debt | $ | $ 250,000 | |||
Subsequent Event | ||||
Debt Instrument, Convertible, Consecutive Trading Days for Calculation of Applicable Market Value | 20 days | |||
Debt Instrument, Convertible, If Applicable Market Value Greater Than Reference Price, Amount Used To Calculate Number of Shares, Numerator | $ / shares | $ 50 | |||
Debt Instrument, Convertible, Conversion Ratio | 1.0655 | |||
Sale of Stock, Consideration Received on Transaction | $ | $ 299,000 | |||
Sale of Stock, Number of Shares Issued in Transaction | shares | 6,372,000 | |||
Entity Common Stock, Shares Outstanding | shares | 59,970,000 |
Risk Management Activities_ Uti
Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2018USD ($)MMBTU | Sep. 30, 2017MMBTU | Dec. 31, 2017MMBTU | |
Derivative [Line Items] | |||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $ | $ 0.1 | ||
Cash Flow Hedging | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount, Energy Measure | 2,236,000 | ||
Future | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | 5,300,000 | 10,250,000 | 8,330,000 |
Derivative, Remaining Maturity | 27 months | 39 months | 36 months |
Commodity Option | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | 9,670,000 | 7,360,000 | 3,540,000 |
Derivative, Remaining Maturity | 16 months | 17 months | 14 months |
Basis Swap | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | 5,140,000 | 9,170,000 | 8,060,000 |
Derivative, Remaining Maturity | 27 months | 39 months | 36 months |
Fixed for Float Swaps Purchased | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | 4,370,000 | 4,600,000 | 3,820,000 |
Derivative, Remaining Maturity | 20 months | 20 months | 29 months |
Credit Risk Derivative Liabilities, at Fair Value | $ | $ 0.7 | ||
Natural Gas Physical Purchases | |||
Derivative [Line Items] | |||
Derivative, Nonmonetary Notional Amount | 19,539,851 | 21,071,714 | 12,826,605 |
Derivative, Remaining Maturity | 33 months | 38 months | 35 months |
Risk Management Activities_ Fin
Risk Management Activities: Financing Activities (Details) $ in Millions | 1 Months Ended |
Jan. 31, 2017USD ($) | |
Interest rate swaps | |
Derivative [Line Items] | |
Derivative Expired During the Period | $ 50 |
Risk Management Activities_ Dis
Risk Management Activities: Discontinued Operations (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale | Sep. 30, 2017bblMMBTU |
Crude Oil | Future | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 54,000 |
Crude Oil | Options Held | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 9,000 |
Natural Gas | Swap | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | MMBTU | 540,000 |
Risk Management Activities_ Cas
Risk Management Activities: Cash Flow Hedges (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ 0 | $ 0 | $ 0 | $ 0 |
Cash Flow Hedging | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (730) | (452) | (2,940) | (1,294) |
Cash Flow Hedging | Designated as Hedging Instrument | ||||
Derivative [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | 760 | 198 | 2,721 | 2,491 |
Cash Flow Hedging | Interest rate swaps | Designated as Hedging Instrument | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 712 | 713 | 2,138 | 2,228 |
Cash Flow Hedging | Commodity Contract | Designated as Hedging Instrument | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 18 | (261) | 802 | (934) |
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | 30 | (254) | (219) | 1,197 |
Interest Expense | Interest rate swaps | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Interest Expense | Cash Flow Hedging | Interest rate swaps | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (712) | (713) | (2,138) | (2,228) |
Net (loss) from Discontinued Operations | Commodity Contract | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | ||
Net (loss) from Discontinued Operations | Cash Flow Hedging | Commodity Contract | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 295 | 954 | ||
Cost of Sales | Commodity Contract | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Cost of Sales | Cash Flow Hedging | Commodity Contract | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ (18) | $ (34) | $ (802) | $ (20) |
Risk Management Activities_ Der
Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Derivative [Line Items] | |||||
Regulatory assets | $ 260,350 | $ 300,594 | $ 260,350 | $ 300,594 | $ 297,454 |
Price Risk Derivative | |||||
Derivative [Line Items] | |||||
Regulatory assets | 6,192 | 11,297 | 6,192 | 11,297 | $ 11,935 |
Not Designated as Hedging Instrument | |||||
Derivative [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | (96) | (375) | 929 | (1,732) | |
Not Designated as Hedging Instrument | Sales Revenue, Net | |||||
Derivative [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | 0 | (53) | 0 | 90 | |
Not Designated as Hedging Instrument | Cost of Sales | |||||
Derivative [Line Items] | |||||
Derivative, Gain (Loss) on Derivative, Net | $ (96) | $ (322) | $ 929 | $ (1,822) |
Fair Value Measurements_ Schedu
Fair Value Measurements: Schedule of Fair Values (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
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 | $ (4,469) | $ (1,282) | $ (2,448) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (8,777) | (11,497) | (11,125) |
Utilities Group | |||
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 | (4,469) | (1,282) | (2,448) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (8,777) | (11,497) | (11,125) |
Estimate of Fair Value Measurement | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 1,413 | 304 | 432 |
Derivative Liabilities, Total | 1,256 | 2,259 | 1,522 |
Estimate of Fair Value Measurement | Utilities Group | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 1,413 | 304 | 432 |
Derivative Liabilities, Fair Value Disclosure | 1,256 | 2,259 | 1,522 |
Fair Value, Inputs, Level 1 | |||
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, Inputs, Level 1 | Utilities Group | |||
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, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Total | 5,882 | 1,586 | 2,880 |
Derivative Liabilities, Total | 10,033 | 13,756 | 12,647 |
Fair Value, Inputs, Level 2 | Utilities Group | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Derivative Assets, Commodity Derivatives | 5,882 | 1,586 | 2,880 |
Derivative Liabilities, Fair Value Disclosure | 10,033 | 13,756 | 12,647 |
Fair Value, Inputs, Level 3 | |||
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, Inputs, Level 3 | Utilities Group | |||
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_ Balanc
Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Designated as Hedging Instrument | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Net | $ 163 | $ 0 | $ 227 |
Derivative Liability, Fair Value, Net | 283 | 884 | 570 |
Not Designated as Hedging Instrument | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Net | 1,250 | 304 | 430 |
Derivative Liability, Fair Value, Net | 973 | 1,375 | 1,066 |
Commodity Contract | Designated as Hedging Instrument | Derivative assets — current | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 142 | 2 | |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | |
Commodity Contract | Designated as Hedging Instrument | Other assets, non-current | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 21 | ||
Derivative Asset, Fair Value, Gross Liability | 0 | ||
Commodity Contract | Designated as Hedging Instrument | Current assets held for sale | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 225 | ||
Derivative Asset, Fair Value, Gross Liability | 0 | ||
Commodity Contract | Designated as Hedging Instrument | Derivative liabilities — current | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 273 | 817 | 422 |
Commodity Contract | Designated as Hedging Instrument | Current liabilities held for sale | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | ||
Derivative Liability, Fair Value, Gross Liability | 89 | ||
Commodity Contract | Designated as Hedging Instrument | Other deferred credits and other liabilities | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 10 | 67 | 49 |
Commodity Contract | Designated as Hedging Instrument | Noncurrent liabilities held for sale | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | ||
Derivative Liability, Fair Value, Gross Liability | 10 | ||
Commodity Contract | Not Designated as Hedging Instrument | Derivative assets — current | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 1,250 | 304 | 430 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 | 0 |
Commodity Contract | Not Designated as Hedging Instrument | Derivative liabilities — current | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 881 | 1,264 | 1,036 |
Commodity Contract | Not Designated as Hedging Instrument | Other deferred credits and other liabilities | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | $ 92 | $ 111 | 15 |
Commodity Contract | Not Designated as Hedging Instrument | Noncurrent liabilities held for sale | |||
Derivatives, Carrying Amount and Fair Value [Line Items] | |||
Derivative Liability, Fair Value, Gross Asset | 0 | ||
Derivative Liability, Fair Value, Gross Liability | $ 15 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Cash and cash equivalents | $ 10,001 | $ 15,420 | $ 13,449 |
Restricted cash | 3,241 | 2,820 | 2,683 |
Notes payable | 112,100 | 211,300 | 225,170 |
Carrying Amount | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Cash and cash equivalents | 10,001 | 15,420 | 13,449 |
Restricted cash | 3,241 | 2,820 | 2,683 |
Notes payable | 112,100 | 211,300 | 225,170 |
Long-term debt, including current maturities | 3,207,132 | 3,115,143 | 3,115,607 |
Fair Value | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Cash and cash equivalents, Fair Value | 10,001 | 15,420 | 13,449 |
Restricted Cash Fair Value Disclosure | 3,241 | 2,820 | 2,683 |
Notes payable, Fair Value | 112,100 | 211,300 | 225,170 |
Long-term debt, including current maturities, Fair Value | $ 3,289,770 | $ 3,350,544 | $ 3,362,971 |
Other Comprehensive Income (L_3
Other Comprehensive Income (Loss): Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Interest expense | $ 36,480 | $ 35,287 | $ 107,360 | $ 105,417 |
Fuel, purchased power and cost of natural gas sold | 80,244 | 86,281 | 432,544 | 404,222 |
Operations and maintenance | 115,477 | 109,258 | 350,099 | 335,707 |
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 29,278 | 46,376 | 176,161 | 199,058 |
Income tax benefit (expense) | (7,477) | (13,478) | 11,784 | (58,518) |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 20,944 | 31,598 | 182,318 | 137,055 |
Reclassification Out Of Accumulated Other Comprehensive Income | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | (1,030) | (535) | (3,649) | (1,562) |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | (730) | (452) | (2,940) | (1,294) |
Income tax benefit (expense) | 149 | 154 | 643 | 435 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | (581) | (298) | (2,297) | (859) |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Interest Rate Contract | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Interest expense | (712) | (713) | (2,138) | (2,228) |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Commodity Contract | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Net (loss) from discontinued operations | 0 | 295 | 0 | 954 |
Fuel, purchased power and cost of natural gas sold | (18) | (34) | (802) | (20) |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Operations and maintenance | 44 | 49 | 133 | 146 |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Operations and maintenance | (621) | (414) | (1,865) | (1,242) |
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment | ||||
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | (577) | (365) | (1,732) | (1,096) |
Income tax benefit (expense) | 128 | 128 | 380 | 393 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $ (449) | $ (237) | $ (1,352) | $ (703) |
Other Comprehensive Income (L_4
Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | $ (41,202) | $ (34,883) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (37,703) | (32,566) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Interest Rate Swaps | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (19,581) | (18,109) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 |
Reclassification from AOCI, Current Period, Tax | 15 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (17,884) | (16,660) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Interest Rate Swaps | Reclassification Out Of Accumulated Other Comprehensive Income | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 1,682 | 1,449 |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Commodity Contract | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (518) | (233) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (168) | 755 |
Reclassification from AOCI, Current Period, Tax | 0 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (71) | (68) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | Commodity Contract | Reclassification Out Of Accumulated Other Comprehensive Income | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 615 | (590) |
Accumulated Defined Benefit Plans Adjustment | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (21,103) | (16,541) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | 0 | 0 |
Reclassification from AOCI, Current Period, Tax | 3 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (19,748) | (15,838) |
Accumulated Defined Benefit Plans Adjustment | Reclassification Out Of Accumulated Other Comprehensive Income | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 1,352 | 703 |
AOCI Attributable to Parent | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (168) | 755 |
Reclassification from AOCI, Current Period, Tax | 18 | |
AOCI Attributable to Parent | Reclassification Out Of Accumulated Other Comprehensive Income | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | $ 3,649 | $ 1,562 |
Supplemental Disclosure of Ca_3
Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Non-cash Investing and Financing Activities from Continuing Operations [Abstract] | ||
Property, plant and equipment acquired with accrued liabilities | $ 49,631 | $ 33,409 |
Increase (decrease) in capitalized assets associated with asset retirement obligations | 155 | 1,362 |
Supplemental Cash Flow Elements [Abstract] | ||
Interest (net of amounts capitalized) | (104,035) | (102,008) |
Income taxes (paid) refunded | $ (14,842) | $ 1 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) $ in Thousands | Jul. 25, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 |
Defined Benefit Pension Plans | |||||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | $ 1,708 | $ 1,759 | $ 5,125 | $ 5,276 | |
Interest cost | 3,867 | 3,880 | 11,602 | 11,640 | |
Expected return on plan assets | (6,185) | (6,130) | (18,555) | (18,388) | |
Prior service cost (benefit) | 15 | 15 | 44 | 44 | |
Net loss (gain) | 2,158 | 1,002 | 6,473 | 3,005 | |
Net periodic benefit cost | 1,563 | 526 | 4,689 | 1,577 | |
Payment for Pension and Other Postretirement Benefits [Abstract] | |||||
Contributions made to the Defined Benefit Pension Plan | $ 13,000 | ||||
Contributions by Employer | 12,700 | 12,700 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 0 | 0 | |||
Estimated Future Employer Contributions in Next Fiscal Year | 12,700 | 12,700 | |||
Defined Benefit Postretirement Healthcare Plans | |||||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 573 | 575 | 1,718 | 1,725 | |
Interest cost | 521 | 533 | 1,563 | 1,600 | |
Expected return on plan assets | (57) | (79) | (170) | (237) | |
Prior service cost (benefit) | (99) | (109) | (297) | (327) | |
Net loss (gain) | 54 | 125 | 162 | 375 | |
Net periodic benefit cost | 992 | 1,045 | 2,976 | 3,136 | |
Payment for Pension and Other Postretirement Benefits [Abstract] | |||||
Contributions by Employer | 1,234 | 3,702 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 1,234 | 1,234 | |||
Estimated Future Employer Contributions in Next Fiscal Year | 3,821 | 3,821 | |||
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans | |||||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 632 | 612 | 1,347 | 2,048 | |
Interest cost | 293 | 319 | 878 | 957 | |
Prior service cost (benefit) | 0 | 0 | 1 | 1 | |
Net loss (gain) | 250 | 251 | 750 | 751 | |
Net periodic benefit cost | 1,175 | $ 1,182 | 2,976 | $ 3,757 | |
Payment for Pension and Other Postretirement Benefits [Abstract] | |||||
Contributions by Employer | 343 | 1,029 | |||
Estimated Future Employer Contributions in Current Fiscal Year | 343 | 343 | |||
Estimated Future Employer Contributions in Next Fiscal Year | $ 1,623 | $ 1,623 |
Commitments and Contingencies_
Commitments and Contingencies: Busch Ranch I (Details) $ in Millions | Sep. 20, 2018USD ($) | Sep. 30, 2018MW |
AltaGas | ||
Long-term Purchase Commitment [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
Business Combination, Consideration Transferred | $ | $ 16 | |
Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 29 | |
Busch Ranch I Wind Farm | Electric Utilities | ||
Long-term Purchase Commitment [Line Items] | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% |
Commitments and Contingencies_2
Commitments and Contingencies: Dividend Restrictions (Details) $ in Millions | Sep. 30, 2018USD ($) |
Utilities Group | |
Related Party Transaction [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 257 |
Discontinued Operations_ Impair
Discontinued Operations: Impairment of Long-Lived Assets (Details) - USD ($) | 3 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
Discontinued Operations, Held-for-sale or Disposed of by Sale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Disposal Group, Including Discontinued Operations, Impairment Of Long-lived Assets (Net of Tax) | $ 0 | $ 13,000,000 |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | |
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | |||
Disposal Group, Including Discontinued Operation, (Gain) Loss On Sale Of Assets | $ 2,900 | ||
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract] | |||
Other current assets | 75 | $ 10,360 | $ 8,457 |
Derivative assets, current and noncurrent | 0 | 0 | 225 |
Deferred income tax assets, noncurrent, net | 0 | 16,966 | 12,571 |
Property, plant and equipment, net | 2,779 | 56,916 | 96,085 |
Other current liabilities | (2,138) | (18,966) | (7,597) |
Derivative liabilities, current and noncurrent | 0 | 0 | (114) |
Deferred income tax liabilities, noncurrent, net | (400) | 0 | 0 |
Other noncurrent liabilities | 0 | (22,808) | (23,319) |
Net assets | $ 316 | $ 42,468 | $ 86,308 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | Apr. 14, 2016 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||||
Federal statutory rate | 21.00% | 35.00% | 21.00% | 35.00% | |
State income tax (net of federal tax effect) | (6.30%) | (3.40%) | 0.40% | 0.30% | |
Percentage depletion in excess of cost | (0.50%) | (0.90%) | (0.40%) | (0.60%) | |
Accounting for uncertain tax positions adjustment | 0.00% | (0.60%) | 0.00% | (0.20%) | |
Noncontrolling interest | (1.30%) | (3.00%) | (1.10%) | (1.90%) | |
IRC 172(f) carryback claim | 0.00% | (1.00%) | |||
Tax credits | (5.30%) | (1.60%) | (2.60%) | (1.60%) | |
Effective tax rate adjustment | 0.00% | 3.90% | 0.00% | 0.30% | |
Flow-through adjustments | (1.50%) | (1.60%) | (0.80%) | (1.20%) | |
TCJA change in estimate | 17.60% | 0.00% | 4.30% | 0.00% | |
AFUDC equity | (0.10%) | 0.00% | (0.10%) | 0.00% | |
Jurisdictional simplification project | (28.10%) | 0.00% | |||
Other tax differences | 1.90% | 1.30% | 0.70% | 0.30% | |
Effective Tax Rate | 25.50% | 29.10% | (6.70%) | 29.40% | |
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | ||||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | $ 5.3 | $ 7.5 |
Income Taxes_ Tax Benefit Relat
Income Taxes: Tax Benefit Related to Legal Restructuring (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Deferred Tax Assets, Goodwill and Intangible Assets | $ 49,000 | |
Deferred income taxes | (14,396) | $ 65,536 |
Other Restructuring | ||
Deferred income taxes | $ 49,000 |
Income Taxes_ TCJA (Details)
Income Taxes: TCJA (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | ||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | $ 5.3 | $ 7.5 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Payables and Accruals [Abstract] | |||
Accrued employee compensation, benefits and withholdings | $ 57,600 | $ 52,467 | $ 52,841 |
Accrued property taxes | 37,660 | 42,029 | 36,993 |
Customer deposits and prepayments | 42,002 | 44,420 | 41,012 |
Accrued interest and contract adjustment payments | 31,139 | 33,822 | 30,977 |
CIAC current portion | 1,552 | 1,552 | 1,575 |
Other (none of which is individually significant) | 31,400 | 45,172 | 43,381 |
Total accrued liabilities | $ 201,353 | $ 219,462 | $ 206,779 |