Document and Entity Information
Document and Entity Information Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Jan. 31, 2019 | Jun. 30, 2018 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | BLACK HILLS CORP /SD/ | ||
Entity Central Index Key | 1,130,464 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Current Fiscal Year End Date | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 60,003,964.507 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 3,239,030,444 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue: | |||
Revenue | $ 1,754,268 | $ 1,680,266 | $ 1,538,916 |
Operating expenses: | |||
Fuel, purchased power and cost of natural gas sold | 625,610 | 563,288 | 499,132 |
Operations and maintenance | 481,706 | 454,605 | 426,603 |
Depreciation, depletion and amortization | 196,328 | 188,246 | 175,533 |
Taxes - property and production | 51,746 | 51,578 | 46,160 |
Other operating expenses | 1,841 | 5,813 | 55,307 |
Total operating expenses | 1,357,231 | 1,263,530 | 1,202,735 |
Operating income | 397,037 | 416,736 | 336,181 |
Interest charges - | |||
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | (143,720) | (140,533) | (139,091) |
Allowance for funds used during construction - borrowed | 2,104 | 2,415 | 2,981 |
Interest income | 1,641 | 1,016 | 1,429 |
Allowance for funds used during construction - equity | 619 | 2,321 | 3,270 |
Other income (expense), net | (1,799) | (213) | 1,124 |
Total other income (expense) | (141,155) | (134,994) | (130,287) |
Income before income taxes | 255,882 | 281,742 | 205,894 |
Income tax benefit (expense) | 23,667 | (73,367) | (59,101) |
Income from continuing operations | 279,549 | 208,375 | 146,793 |
Net (loss) from discontinued operations | (6,887) | (17,099) | (64,162) |
Net income | 272,662 | 191,276 | 82,631 |
Net income attributable to noncontrolling interest | (14,220) | (14,242) | (9,661) |
Net income (loss) available for common stock | 258,442 | 177,034 | 72,970 |
Amounts attributable to common shareholders: | |||
Net income from continuing operations | 265,329 | 194,133 | 137,132 |
Net (loss) from discontinued operations | (6,887) | (17,099) | (64,162) |
Net income (loss) available for common stock | $ 258,442 | $ 177,034 | $ 72,970 |
Earnings (loss) per share of common stock, Basic - | |||
Earnings from continuing operations, Basic (usd per share) | $ 4.88 | $ 3.65 | $ 2.64 |
(Loss) from discontinued operations per share, Basic (usd per share) | (0.13) | (0.32) | (1.23) |
Total earnings (loss) per share of common stock, Basic (usd per share) | 4.75 | 3.33 | 1.41 |
Earnings (loss) per share of common stock, Diluted - | |||
Earnings from continuing operations, Diluted (usd per share) | 4.78 | 3.52 | 2.57 |
(Loss) from discontinued operations, Diluted (usd per share) | (0.12) | (0.31) | (1.20) |
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 4.66 | $ 3.21 | $ 1.37 |
Weighted average common shares outstanding: | |||
Basic | 54,420 | 53,221 | 51,922 |
Diluted | 55,486 | 55,120 | 53,271 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Net income (loss) | $ 272,662 | $ 191,276 | $ 82,631 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax [Abstract] | |||
Benefit plan liability adjustments - net gain (loss) (net of tax of $(660), $1,030 and $757, respectively) | 2,155 | (1,890) | (1,738) |
Benefit plan liability adjustments - prior service (costs) (net of tax of $0, $0 and $107, respectively) | 0 | 0 | (247) |
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(586), $(585) and $(600), respectively) | 1,901 | 1,072 | 1,378 |
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $43, $69 and $67, respectively) | (135) | (128) | (154) |
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract] | |||
Other comprehensive income (loss), net of tax | 7,027 | 681 | (25,828) |
Comprehensive income | 279,689 | 191,957 | 56,803 |
Net income attributable to noncontrolling interest | (14,220) | (14,242) | (9,661) |
Comprehensive income available for common stock | 265,469 | 177,715 | 47,142 |
Interest rate swaps | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract] | |||
Net unrealized gains (losses) net of tax | 0 | 0 | (20,302) |
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax | 2,252 | 1,912 | 2,534 |
Commodity derivatives | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract] | |||
Net unrealized gains (losses) net of tax | 755 | 231 | (361) |
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax | $ 99 | $ (516) | $ (6,938) |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Benefit plan liability adjustments - net gain (loss), Tax | $ (660) | $ 1,030 | $ 757 |
Benefit plan liability adjustments - prior service (costs), Tax | 0 | 0 | 107 |
Reclassification adjustment of benefit plan liability - net gain (loss) tax | (586) | (585) | (600) |
Reclassification adjustment of benefit plan liability - prior service cost, tax | 43 | 69 | 67 |
Interest Rate Swap | |||
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax | 0 | 0 | 10,920 |
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax | (599) | (1,029) | (1,365) |
Commodity Contract | |||
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax | (228) | (135) | 212 |
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax | $ (31) | $ 154 | $ 4,067 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 20,776 | $ 15,420 |
Restricted cash and equivalents | 3,369 | 2,820 |
Accounts receivable, net | 269,153 | 248,330 |
Materials, supplies and fuel | 117,299 | 113,283 |
Derivative assets, current | 1,500 | 304 |
Income tax receivable, net | 12,978 | 0 |
Regulatory assets, current | 48,776 | 81,016 |
Other current assets | 29,982 | 25,367 |
Current assets held for sale | 0 | 84,242 |
Total current assets | 503,833 | 570,782 |
Investments | 41,013 | 13,090 |
Property, plant and equipment | 6,000,015 | 5,567,518 |
Less accumulated depreciation and depletion | (1,145,136) | (1,026,088) |
Total property, plant and equipment, net | 4,854,879 | 4,541,430 |
Other assets: | ||
Goodwill | 1,299,454 | 1,299,454 |
Intangible assets, net | 14,337 | 7,559 |
Regulatory assets, non-current | 235,459 | 216,438 |
Other assets, non-current | 14,352 | 10,149 |
Total other assets, non-current | 1,563,602 | 1,533,600 |
TOTAL ASSETS | 6,963,327 | 6,658,902 |
Current liabilities: | ||
Accounts payable | 210,609 | 160,887 |
Accrued liabilities | 215,501 | 219,462 |
Derivative liabilities, current | 947 | 2,081 |
Accrued income tax, net | 0 | 1,022 |
Regulatory liabilities, current | 29,810 | 6,832 |
Notes payable | 185,620 | 211,300 |
Current maturities of long-term debt | 5,743 | 5,743 |
Current liabilities held for sale | 0 | 41,774 |
Total current liabilities | 648,230 | 649,101 |
Long-term debt, net of current maturities | 2,950,835 | 3,109,400 |
Deferred credits and other liabilities: | ||
Deferred income tax liabilities, net | 311,331 | 336,520 |
Regulatory liabilities, non-current | 510,984 | 478,294 |
Benefit plan liabilities | 145,147 | 159,646 |
Other deferred credits and other liabilities | 109,377 | 105,735 |
Total deferred credits and other liabilities | 1,076,839 | 1,080,195 |
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20) | ||
Stockholders’ equity - | ||
Common stock $1 par value; 100,000,000 shares authorized; issued: 60,048,567 and 53,579,986, respectively | 60,049 | 53,580 |
Additional paid-in capital | 1,450,569 | 1,150,285 |
Retained earnings | 700,396 | 548,617 |
Treasury stock at cost - 44,253 and 39,064, respectively | (2,510) | (2,306) |
Accumulated other comprehensive income (loss) | (26,916) | (41,202) |
Total stockholders’ equity | 2,181,588 | 1,708,974 |
Noncontrolling interest | 105,835 | 111,232 |
Total equity | 2,287,423 | 1,820,206 |
TOTAL LIABILITIES AND TOTAL EQUITY | $ 6,963,327 | $ 6,658,902 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Common Stock, Par Value (usd per share) | $ 1 | $ 1 |
Treasury Stock, Shares | 44,253 | 39,064 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 60,048,567 | 53,579,986 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating activities: | |||
Net income | $ 272,662 | $ 191,276 | $ 82,631 |
Loss from discontinued operations, net of tax | 6,887 | 17,099 | 64,162 |
Income (loss) from continuing operations | 279,549 | 208,375 | 146,793 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 196,328 | 188,246 | 175,533 |
Deferred financing cost amortization | 7,845 | 8,261 | 6,180 |
Stock compensation | 12,390 | 7,626 | 10,885 |
Deferred income taxes | (24,239) | 80,992 | 82,704 |
Employee benefit plans | 14,068 | 10,141 | 14,291 |
Other adjustments, net | 5,836 | (4,773) | (5,519) |
Change in certain operating assets and liabilities: | |||
Materials, supplies and fuel | (2,919) | (10,089) | 1,211 |
Accounts receivable and other current assets | (45,966) | 4,534 | (27,172) |
Accounts payable and other current liabilities | 5,305 | (28,222) | (33,023) |
Regulatory assets | 33,608 | (15,407) | 3,614 |
Regulatory liabilities | 18,533 | (4,536) | (14,082) |
Contributions to defined benefit pension plans | (12,700) | (27,700) | (14,200) |
Interest rate swap settlement | 0 | 0 | (28,820) |
Other operating activities, net | 6,689 | (8,418) | (660) |
Net cash provided by operating activities of continuing operations | 494,327 | 409,030 | 317,735 |
Net cash provided by (used in) operating activities of discontinued operations | (5,516) | 19,231 | 2,744 |
Net cash provided by operating activities | 488,811 | 428,261 | 320,479 |
Investing activities: | |||
Property, plant and equipment additions | (457,524) | (326,010) | (454,952) |
Acquisition of net assets, net of long-term debt assumed | 0 | 0 | (1,124,238) |
Purchase of investment | (24,429) | 0 | 0 |
Other investing activities | (4,281) | 1,011 | (562) |
Net cash (used in) investing activities of continuing operations | (486,234) | (324,999) | (1,579,752) |
Net cash provided by (used in) investing activities of discontinued operations | 20,385 | 7,881 | (8,413) |
Net cash (used in) investing activities | (465,849) | (317,118) | (1,588,165) |
Financing activities: | |||
Dividends paid on common stock | (106,591) | (96,744) | (87,570) |
Common stock issued | 300,834 | 4,408 | 121,619 |
Net increase (decrease) in commercial paper and short-term borrowings | (25,680) | 114,700 | 19,800 |
Long-term debt - issuance | 700,000 | 0 | 1,767,608 |
Long-term debt - repayments | (854,743) | (105,743) | (1,164,308) |
Sale of noncontrolling interest | 0 | 0 | 216,370 |
Distributions to noncontrolling interests | (19,617) | (18,397) | (9,561) |
Other financing activities | (11,260) | (6,919) | (22,960) |
Net cash provided by (used in) financing activities | (17,057) | (108,695) | 840,998 |
Net change in cash, restricted cash and cash equivalents | 5,905 | 2,448 | (426,688) |
Cash and cash equivalents: | |||
Cash, restricted cash and cash equivalents beginning of year | 18,240 | 15,792 | 442,480 |
Cash, restricted cash and cash equivalents end of year | $ 24,145 | $ 18,240 | $ 15,792 |
Consolidated Statements Of Equi
Consolidated Statements Of Equity - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest |
Total equity at Dec. 31, 2015 | $ 1,465,867 | $ 51,232 | $ (1,888) | $ 953,044 | $ 472,534 | $ (9,055) | $ 0 |
Common Stock, Shares, Outstanding at Dec. 31, 2015 | 51,231,861 | ||||||
Treasury Stock, Shares at Dec. 31, 2015 | 39,720 | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) available for common stock | 72,970 | 72,970 | |||||
Net income attributable to noncontrolling interest | (9,661) | 9,661 | |||||
Net income (loss) | 82,631 | ||||||
Other comprehensive income (loss), net of tax | (25,828) | (25,828) | |||||
Dividends on common stock | (87,570) | (87,570) | |||||
Share-based compensation, shares | (145,634) | (16,165) | |||||
Share-based compensation | 5,479 | $ 146 | $ 668 | 4,665 | |||
Issuance of common stock, shares | 1,968,738 | ||||||
Issuance of common stock | 119,990 | $ 1,969 | 118,021 | ||||
Issuance costs | (1,566) | (1,566) | |||||
Dividend reinvestment and stock purchase plan, shares | 51,234 | ||||||
Dividend reinvestment and stock purchase plan | 2,983 | $ 50 | 2,933 | ||||
Other stock transactions, shares | (8,297) | ||||||
Other stock transactions | 476 | $ 429 | 47 | ||||
Sale of noncontrolling interest | 177,233 | 61,838 | 115,395 | ||||
Distributions to noncontrolling interest | (9,561) | (9,561) | |||||
Common Stock, Shares, Outstanding at Dec. 31, 2016 | 53,397,467 | ||||||
Total equity at Dec. 31, 2016 | $ 1,730,134 | $ 53,397 | $ (791) | 1,138,982 | 457,934 | (34,883) | 115,495 |
Treasury Stock, Shares at Dec. 31, 2016 | 15,258 | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.68 | ||||||
Net income (loss) available for common stock | $ 177,034 | 177,034 | |||||
Net income attributable to noncontrolling interest | (14,242) | 14,242 | |||||
Net income (loss) | 191,276 | ||||||
Other comprehensive income (loss), net of tax | 681 | 681 | |||||
Reclassification of certain tax effects from AOCI | 0 | 7,000 | (7,000) | ||||
Dividends on common stock | (96,744) | (96,744) | |||||
Share-based compensation, shares | (134,266) | (23,806) | |||||
Share-based compensation | 7,567 | $ 134 | $ (1,515) | 8,948 | |||
Tax effect of share-based compensation | 3,717 | 533 | |||||
Issuance costs | (189) | (189) | |||||
Dividend reinvestment and stock purchase plan, shares | 48,253 | ||||||
Dividend reinvestment and stock purchase plan | 3,156 | $ 49 | 3,107 | ||||
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | (1,096) | 209 | |||||
Distributions to noncontrolling interest | (19,392) | (18,505) | |||||
Common Stock, Shares, Outstanding at Dec. 31, 2017 | 53,579,986 | ||||||
Total equity at Dec. 31, 2017 | $ 1,820,206 | $ 53,580 | $ (2,306) | 1,150,285 | 548,617 | (41,202) | 111,232 |
Treasury Stock, Shares at Dec. 31, 2017 | 39,064 | 39,064 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.81 | ||||||
Net income (loss) available for common stock | $ 258,442 | 258,442 | |||||
Net income attributable to noncontrolling interest | (14,220) | 14,220 | |||||
Net income (loss) | 272,662 | ||||||
Other comprehensive income (loss), net of tax | 7,027 | 7,027 | |||||
Reclassification of certain tax effects from AOCI | 740 | 0 | 740 | ||||
Reclassification to regulatory asset | 6,519 | 6,519 | |||||
Dividends on common stock | (106,591) | (106,591) | |||||
Share-based compensation, shares | (92,830) | (5,189) | |||||
Share-based compensation | 7,190 | $ 93 | $ (204) | 7,301 | |||
Issuance of common stock, shares | 6,371,690 | ||||||
Issuance of common stock | 299,000 | $ 6,372 | 292,628 | ||||
Issuance costs | (15) | (15) | |||||
Dividend reinvestment and stock purchase plan, shares | 4,061 | ||||||
Dividend reinvestment and stock purchase plan | 220 | $ 4 | 216 | ||||
Other stock transactions | 82 | 154 | (72) | ||||
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests | 0 | 0 | |||||
Distributions to noncontrolling interest | (19,617) | (19,617) | |||||
Common Stock, Shares, Outstanding at Dec. 31, 2018 | 60,048,567 | ||||||
Total equity at Dec. 31, 2018 | $ 2,287,423 | $ 60,049 | $ (2,510) | $ 1,450,569 | $ 700,396 | $ (26,916) | $ 105,835 |
Treasury Stock, Shares at Dec. 31, 2018 | 44,253 | 44,253 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.93 |
Business Description And Signif
Business Description And Significant Accounting Policies: | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business Description and Significant Accounting Policies | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Segment Reporting 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. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. All of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21 . Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12 . Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as 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 and cash equivalents. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands): 2018 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,721 $ 35,125 $ (448 ) $ 74,398 Gas Utilities 96,123 90,521 (2,592 ) 184,052 Power Generation 1,876 — — 1,876 Mining 3,988 — — 3,988 Corporate 5,008 — (169 ) 4,839 Total $ 146,716 $ 125,646 $ (3,209 ) $ 269,153 2017 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts 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 Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Adjustments (a) Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2018 $ 3,081 $ — $ 6,859 $ 4,092 $ (10,823 ) $ 3,209 2017 $ 2,392 $ — $ 4,926 $ 8,262 $ (12,499 ) $ 3,081 2016 $ 1,741 $ 2,158 $ 2,704 $ 4,915 $ (9,126 ) $ 2,392 ________________ (a) Represents allowance balances added with the SourceGas acquisition. Revenue Recognition Revenue is 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. 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 Gas and Electric Utilities 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 year ended December 31, 2018 . Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194 ) $ 1,461,317 Transportation — 140,705 — — (1,348 ) 139,357 Wholesale 33,687 — 52,396 — (46,562 ) 39,521 Market - off-system sales 24,799 866 — — (8,102 ) 17,563 Transmission/Other 56,209 49,402 — — (14,827 ) 90,784 Revenue from contracts with customers 709,024 1,024,352 52,396 65,803 (103,033 ) 1,748,542 Other revenues 2,427 955 36,556 2,230 (36,442 ) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 88,952 $ 68,033 $ (139,475 ) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194 ) $ 33,609 Services transferred over time 709,024 1,024,352 52,396 — (70,839 ) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 52,396 $ 65,803 $ (103,033 ) $ 1,748,542 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 table 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 Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Black Hills 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 $37 million during the year ended December 31, 2018. As of December 31, 2018 , $19 million has been returned to customers and approximately $18 million remains in reserve as a current regulatory liability. Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. 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 above. 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. Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2018 2017 Materials and supplies $ 75,081 $ 69,732 Fuel - Electric Utilities 2,850 2,962 Natural gas in storage 39,368 40,589 Total materials, supplies and fuel $ 117,299 $ 113,283 Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. 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. 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 December 31, 2018. The following table presents the carrying value of our investments (in thousands) as of December 31: 2018 2017 Cost method investment $ 28,201 $ — Cash surrender value of life insurance contracts 12,812 13,090 Total investments $ 41,013 $ 13,090 Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2018 2017 Accrued employee compensation, benefits and withholdings $ 63,742 $ 52,467 Accrued property taxes 42,510 42,029 Customer deposits and prepayments 43,574 44,420 Accrued interest 31,759 33,822 CIAC current portion 1,485 1,552 Other (none of which is individually significant) 32,431 45,172 Total accrued liabilities $ 215,501 $ 219,462 Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2017 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2018 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years . Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2018 2017 2016 Intangible assets, net, beginning balance $ 7,559 $ 8,392 $ 3,380 Additions (a) 7,602 — 5,522 Amortization expense (b) (824 ) (833 ) (510 ) Intangible assets, net, ending balance $ 14,337 $ 7,559 $ 8,392 _________________ (a) The 2018 addition is related to the Busch Ranch 1 Wind Farm contract intangible asset. See Note 4 for further information. (b) Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years. Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. Additional information is included in Note 8 and 21 . Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not have any Level 3 investments. Valuation Methodologies for Derivatives The commodity contracts for the Electric and Gas Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and options Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition, the fair value for the over-the-counter swaps and option derivatives, if material, include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. Additional information on fair value measurements is included in Notes 10 , 11 and 18 . Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for t |
Acquisition_
Acquisition: | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisition | ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , including the assumption of $760 million in debt at closing. SourceGas is a 100% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million Equity Units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million for the year ending December 31, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Consolidated Statements of Income. Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income of $15 million , attributable to SourceGas for the period from February 12 through December 31, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion , net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million , resulted in goodwill of $940 million . We had up to one year from the acquisition date to finalize the purchase price allocation. The working capital adjustment received in 2016 of $11 million reflected changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities. (in thousands) Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration paid, net of working capital adjustment received $ 1,124,238 Allocation of Purchase Price: Current Assets $ 112,983 Property, plant & equipment, net 1,058,093 Goodwill 939,695 Deferred charges and other assets, excluding goodwill 133,299 Current liabilities (172,454 ) Long-term debt (758,874 ) Deferred credits and other liabilities (188,504 ) Total consideration paid, net of working-capital adjustment received $ 1,124,238 Conditions of SourceGas Acquisition Regulatory Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions. We have met all conditions as set forth in the commissions’ approval orders. Pro Forma Results (unaudited) We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2016: Pro Forma Results December 31, 2016 (in thousands, except per share amounts) Revenue $ 1,617,878 Income from continuing operations $ 177,040 Net income (loss) $ 112,878 Earnings from continuing operations per share, Basic $ 3.41 Earnings from continuing operations per share, Diluted $ 3.32 We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2016, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2016, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37% . These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2016, or that may be obtained in the future. Seller’s noncontrolling interest As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder for the 0.5% retained interest. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million . |
Property, Plant And Equipment_
Property, Plant And Equipment: | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2018 2017 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,318,643 41 $ 1,315,044 39 32 46 Electric transmission 437,082 51 407,203 51 48 53 Electric distribution 793,725 48 755,213 48 45 50 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 233,531 28 232,842 31 26 28 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 3,049,292 2,976,613 Construction work in progress 60,480 13,595 Total electric plant 3,109,772 2,990,208 Less accumulated depreciation and amortization 706,869 644,022 Electric plant net of accumulated depreciation and amortization $ 2,402,903 $ 2,346,186 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining. (b) Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031. 2018 2017 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 13,580 35 $ 10,495 35 24 71 Gas transmission 423,873 48 366,433 48 22 66 Gas distribution 1,595,644 42 1,413,431 42 33 47 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciated (a) 46,369 N/A 47,466 N/A N/A N/A Storage 29,335 30 28,520 31 28 38 General 355,920 19 336,869 19 10 24 Total gas plant in service 2,468,260 2,206,753 Construction work in progress 38,271 44,440 Total gas plant 2,506,531 2,251,193 Less accumulated depreciation and amortization 279,580 229,170 Gas plant net of accumulated depreciation and amortization $ 2,226,951 $ 2,022,023 _____________ (a) Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides. 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 173,997 $ 11,796 $ 185,793 $ 64,273 $ 121,520 31 2 40 Mining $ 175,650 $ — $ 175,650 $ 111,689 $ 63,961 13 2 59 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 155,569 $ 224 $ 155,793 $ 57,813 $ 97,980 33 2 40 Mining $ 158,370 $ — $ 158,370 $ 108,844 $ 49,526 14 2 59 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 16,548 $ 22,269 $ 670 $ 17,945 $ 39,544 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $18 million . 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,580 $ 6,374 $ 11,954 $ 309 $ 14,070 $ 25,715 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million . |
Jointly Owned Facilities_
Jointly Owned Facilities: | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Jointly Owned Facilities | JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. • South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. • South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the SPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie. • South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant. • Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations. At December 31, 2018 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 115,198 $ 384 $ 61,730 Transmission Tie $ 20,855 $ 1,860 $ 6,667 Wygen I $ 119,273 $ 498 $ 44,155 Wygen III $ 140,072 $ 645 $ 22,647 Jointly Owned facility - Related Party Colorado Electric owns 50% of the Busch Ranch I Wind Farm while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in the 29 MW Busch Ranch I Wind Farm from AltaGas for $16 million . Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation will provide its share of energy from the wind farm to Colorado Electric through a new PPA, which replaces the PPA Colorado Electric had with AltaGas, expiring in October 2037. |
Business Segment Information_
Business Segment Information: | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting Information, Additional Information [Abstract] | |
Business Segment Information | BUSINESS SEGMENT INFORMATION 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. Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2018 2017 Electric (a) $ 2,895,577 $ 2,906,275 Gas 3,623,475 3,426,466 Power Generation (a) 154,203 60,852 Mining 80,594 65,455 Corporate and Other 209,478 115,612 Discontinued operations (b) — 84,242 Total assets $ 6,963,327 $ 6,658,902 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information. Capital Expenditures (a) for the years ended December 31, 2018 2017 Capital expenditures Electric Utilities $ 152,524 $ 138,060 Gas Utilities 288,438 184,389 Power Generation 30,945 1,864 Mining 18,794 6,708 Corporate and Other 11,723 6,668 Total capital expenditures of continuing operations 502,424 337,689 Total capital expenditures of discontinued operations 2,402 23,222 Total capital expenditures $ 504,826 $ 360,911 _________________ (a) Includes accruals for property, plant and equipment. Property, Plant and Equipment as of December 31, 2018 2017 Electric Utilities (a) $ 3,109,772 $ 2,990,208 Gas Utilities 2,506,531 2,251,193 Power Generation (a) 185,793 155,793 Mining 175,650 158,370 Corporate and Other 22,269 11,954 Total property, plant and equipment $ 6,000,015 $ 5,567,518 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — — — 5,726 688,699 1,023,783 7,246 34,540 — — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 46,563 32,194 148 (103,181 ) — — Other revenues — — 35,143 1,299 379,775 (416,217 ) — — 22,752 1,524 81,706 33,493 379,923 (519,398 ) — — Total revenue 711,451 1,025,307 88,952 68,033 379,923 (519,398 ) — 1,754,268 Fuel, purchased power and cost of natural gas sold 277,093 462,153 — — 43 (113,679 ) — 625,610 Operations and maintenance 186,175 291,481 33,727 43,728 324,917 (344,735 ) — 535,293 Depreciation, depletion and amortization 98,639 86,434 6,913 7,965 21,161 (24,784 ) — 196,328 Operating income (loss) 149,544 185,239 48,312 16,340 33,802 (36,200 ) — 397,037 Interest expense (55,660 ) (85,760 ) (5,178 ) (538 ) (150,455 ) 155,975 — (141,616 ) Interest income 2,993 5,580 183 2 113,188 (120,305 ) — 1,641 Other income (expense), net (1,235 ) (431 ) (53 ) 164 456,481 (456,106 ) — (1,180 ) Income tax benefit (expense) (a) (16,702 ) 55,655 (8,267 ) (3,069 ) (3,804 ) (146 ) — 23,667 Income (loss) from continuing operations 78,940 160,283 34,997 12,899 449,212 (456,782 ) — 279,549 (Loss) from discontinued operations, net of tax — — — — — — (6,887 ) (6,887 ) Net income (loss) 78,940 160,283 34,997 12,899 449,212 (456,782 ) (6,887 ) 272,662 Net income attributable to noncontrolling interest — — (14,220 ) — — — — (14,220 ) Net income (loss) available for common stock $ 78,940 $ 160,283 $ 20,777 $ 12,899 $ 449,212 $ (456,782 ) $ (6,887 ) $ 258,442 ________________ (a) Income tax benefit (expense) includes a tax benefit of $73 million at our Gas Utilities resulting from legal entity restructuring. See Note 15 . Consolidating Income Statement Year ended December 31, 2017 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ — $ 1,680,266 Intercompany revenue 14,705 35 84,283 31,158 344,685 (474,866 ) — — Total revenue 704,650 947,630 91,546 66,621 344,685 (474,866 ) — 1,680,266 Fuel, purchased power and cost of natural gas sold 268,405 409,603 — — 151 (114,871 ) — 563,288 Operations and maintenance 172,307 269,190 32,382 44,882 296,067 (302,832 ) — 511,996 Depreciation, depletion and amortization 93,315 83,732 5,993 8,239 21,031 (24,064 ) — 188,246 Operating income (loss) 170,623 185,105 53,171 13,500 27,436 (33,099 ) — 416,736 Interest expense (55,229 ) (80,829 ) (3,959 ) (228 ) (152,416 ) 154,543 — (138,118 ) Interest income 2,955 2,254 1,123 23 115,382 (120,721 ) — 1,016 Other income (expense), net 1,730 (829 ) (54 ) 2,191 330,373 (331,303 ) — 2,108 Income tax benefit (expense) (9,997 ) (39,799 ) 10,333 (1,100 ) (32,433 ) (371 ) — (73,367 ) Income (loss) from continuing operations 110,082 65,902 60,614 14,386 288,342 (330,951 ) — 208,375 (Loss) from discontinued operations, net of tax (a) — — — — — — (17,099 ) (17,099 ) Net income (loss) 110,082 65,902 60,614 14,386 288,342 (330,951 ) (17,099 ) 191,276 Net income attributable to noncontrolling interest — (107 ) (14,135 ) — — — — (14,242 ) Net income (loss) available for common stock $ 110,082 $ 65,795 $ 46,479 $ 14,386 $ 288,342 $ (330,951 ) $ (17,099 ) $ 177,034 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ — $ — $ — $ 1,538,916 Intercompany revenue 12,951 — 83,955 31,213 347,500 (475,619 ) — — Total revenue 677,281 838,343 91,131 60,280 347,500 (475,619 ) — 1,538,916 Fuel, purchased power and cost of natural gas sold 261,349 352,165 — — 456 (114,838 ) — 499,132 Operations and maintenance 158,134 245,826 32,636 39,576 378,744 (326,846 ) — 528,070 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 22,930 (23,827 ) — 175,533 Operating income (loss) 173,153 162,017 54,391 11,358 (54,630 ) (10,108 ) — 336,181 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (114,597 ) 115,469 — (136,110 ) Interest income 5,946 1,573 1,983 24 97,147 (105,244 ) — 1,429 Other income (expense), net 3,193 184 2 2,209 179,838 (181,032 ) — 4,394 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 28,398 457 — (59,101 ) Income (loss) from continuing operations 85,827 59,726 35,489 10,053 136,156 (180,458 ) — 146,793 (Loss) from discontinued operations, net of tax (a) — — — — — — (64,162 ) (64,162 ) Net income (loss) 85,827 59,726 35,489 10,053 136,156 (180,458 ) (64,162 ) 82,631 Net income attributable to noncontrolling interest — (102 ) (9,559 ) — — — — (9,661 ) Net income (loss) available for common stock $ 85,827 $ 59,624 $ 25,930 $ 10,053 $ 136,156 $ (180,458 ) $ (64,162 ) $ 72,970 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . Corporate expense reallocation In accordance with GAAP, indirect corporate operating costs previously allocated to BHEP were not reclassified to discontinued operations. These corporate operating costs for 2017 were reallocated to our operating segments; allocated interest was reclassified to Corporate and Other. Indirect corporate operating costs for 2016 were reclassified to Corporate and Other. The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 is as follows (in thousands): Year Ended Business Segment December 31, 2017 December 31, 2016 Electric Utilities $ 1,323 $ 2,079 Gas Utilities 1,571 2,292 Power Generation 177 320 Mining 101 196 Total reportable segments 3,172 4,887 Corporate and Other (a) 6,405 6,037 Total $ 9,577 $ 10,924 ________________________ (a) Includes interest allocations in 2017 and 2016 of approximately $4.9 million and $5.6 million , respectively. |
Long-Term Debt_
Long-Term Debt: | 12 Months Ended |
Dec. 31, 2018 | |
Long-term Debt, Unclassified [Abstract] | |
Long-Term Debt | LONG-TERM DEBT Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2018 December 31, 2018 December 31, 2017 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% — 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% — 250,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes due 2033 May 1, 2033 4.35% 400,000 — Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Corporate term loan due 2019 August 9, 2019 2.55% — 300,000 Corporate term loan due 2020 (a) July 30, 2020 3.16% 300,000 — Corporate term loan due 2021 June 7, 2021 2.32% 12,921 18,664 Total Corporate debt 2,437,921 2,592,664 Less unamortized debt discount (5,122 ) (3,808 ) Total Corporate debt, net 2,432,799 2,588,856 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 1.73% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 1.73% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 1.93% 2,855 2,855 Total Electric Utilities debt 544,855 544,855 Less unamortized debt discount (86 ) (90 ) Total Electric Utilities debt, net 544,769 544,765 Total long-term debt 2,977,568 3,133,621 Less current maturities 5,743 5,743 Less unamortized deferred financing costs (d) 20,990 18,478 Long-term debt, net of current maturities and deferred financing costs $ 2,950,835 $ 3,109,400 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2018 and December 31, 2017 , respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2019 $ 5,743 2020 $ 505,743 2021 $ 8,435 2022 $ — 2023 $ 525,000 Thereafter $ 1,937,855 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2018 . Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds. Debt Transactions On December 12, 2018, we paid off the $250 million , 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this 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 Note 12). 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 December 31, 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 December 31, 2018. On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. Amortization Expense Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2018 2018 2017 2016 $ 20,990 $ 2,829 $ 3,349 $ 3,861 Dividend Restrictions Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2018 , we were in compliance with these 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 shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2018 : • Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2018 , the restricted net assets at our Electric and Gas Utilities were approximately $257 million . |
Notes Payable_
Notes Payable: | 12 Months Ended |
Dec. 31, 2018 | |
Notes Payable [Abstract] | |
Notes Payable | NOTES PAYABLE Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2018 , we were in compliance with all of these financial covenants. We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): Balance Outstanding at December 31, 2018 December 31, 2017 CP Program $ 185,620 $ 211,300 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 December 31, 2018 . Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 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 2018 were $(26) million and our notes outstanding as of December 31, 2018 were $186 million . As of December 31, 2018, the weighted average interest rate on CP Program borrowings was 2.88% . As of December 31, 2018 and December 31, 2017 , we had outstanding letters of credit totaling approximately $22 million and approximately $27 million , respectively. Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income (Loss). See Note 6 above for additional details. Debt Covenants Under our Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 . Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: At December 31, 2018 Covenant Requirement at December 31, 2018 Consolidated Indebtedness to Capitalization Ratio 59 % Less than 65 % |
Asset Retirement Obligations_
Asset Retirement Obligations: | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2017 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (b) December 31, 2018 Electric Utilities $ 6,287 $ — $ — $ 269 $ 2 $ 6,558 Gas Utilities 33,238 152 — 1,237 — 34,627 Mining 12,499 — (4 ) 649 2,471 15,615 Total $ 52,024 $ 152 $ (4 ) $ 2,155 $ 2,473 $ 56,800 December 31, 2016 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) December 31, 2017 Electric Utilities $ 4,661 $ — $ (4 ) $ 268 $ 1,362 $ 6,287 Gas Utilities 29,775 — — 1,142 2,321 33,238 Mining 12,440 — (107 ) 651 (485 ) 12,499 Total $ 46,876 $ — $ (111 ) $ 2,061 $ 3,198 $ 52,024 _____________________ (a) The Gas Utilities’ Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (b) The increase in the Mining Revision to Prior Estimates was primarily driven by higher costs associated with back-filling the pit with overburden removed during the mining process. We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time. We had identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells. These obligations were classified as held for sale at December 31, 2017. See Note 21 . |
Risk Management Activities_
Risk Management Activities: | 12 Months Ended |
Dec. 31, 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 operations 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. Valuation methodologies for our derivatives are detailed within Note 1 . Market Risk Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. 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 several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand; • Interest rate risk associated with our variable 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 upon 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 credit exposure at December 31, 2018 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10 . 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 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 Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss). 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 January 2019 through December 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price 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 Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly. The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2018 December 31, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 4,000,000 24 8,330,000 36 Natural gas options purchased, net 4,320,000 13 3,540,000 14 Natural gas basis swaps purchased 3,960,000 24 8,060,000 36 Natural gas over-the-counter swaps, net (b) 3,660,000 24 3,820,000 29 Natural gas physical commitments, net (c) 18,325,852 30 12,826,605 35 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2018 , 1,542,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude contracts that qualify for normal purchase, normal sales exception. Based on December 31, 2018 prices, a $0.4 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. Cash Flow Hedges The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2018 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 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 $ (2,851 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (130 ) Fuel, purchased power and cost of natural gas sold — Total impact from cash flow hedges $ (2,981 ) $ — December 31, 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 $ (2,941 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 913 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Fuel, purchased power and cost of natural gas sold (75 ) Total $ (2,271 ) $ (75 ) December 31, 2016 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 $ (3,899 ) Interest expense $ (953 ) Commodity derivatives Net (loss) from discontinued operations 11,019 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) Fuel, purchased power and cost of natural gas sold — Total $ 7,106 $ (953 ) The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2018 , 2017 and 2016 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred. December 31, 2018 December 31, 2017 December 31, 2016 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ — $ — $ (31,222 ) Forward commodity contracts 983 366 (573 ) Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,851 2,941 3,899 Forward commodity contracts 130 (670 ) (11,005 ) Total other comprehensive income (loss) from hedging $ 3,964 $ 2,637 $ (38,901 ) Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2018 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 2018 December 31, 2017 December 31, 2016 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 Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ — $ (50 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold 1,101 (2,207 ) 940 $ 1,101 $ (2,207 ) $ 890 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 and $12 million at December 31, 2018 and 2017 , respectively. |
Fair Value Measurements_
Fair Value Measurements: | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances during 2018 or 2017 . 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. A discussion of fair value of financial instruments is included in Note 11 . Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 21. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Total $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Liabilities: Commodity derivatives - Utilities $ — $ 6,801 $ — $ (5,794 ) $ 1,007 Total $ — $ 6,801 $ — $ (5,794 ) $ 1,007 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total 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 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 as of December 31, (in thousands): December 31, Balance Sheet Location 2018 2017 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 415 $ — Noncurrent commodity derivatives Other assets, non-current 18 — Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (114 ) (817 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (4 ) (67 ) Total derivatives designated as hedges $ 315 $ (884 ) Not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,085 $ 304 Noncurrent commodity derivatives Other assets, non-current 1 — Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (833 ) (1,264 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (56 ) (111 ) Total derivatives not designated as hedges $ 197 $ (1,071 ) Derivatives Offsetting It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities. As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2018 and 2017 , to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure. Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2018 was as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,408 $ (1,408 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 1,519 — 1,519 Total derivative assets $ 2,927 $ (1,408 ) $ 1,519 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 5,794 $ (5,794 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 1,007 — 1,007 Total derivative liabilities $ 6,801 $ (5,794 ) $ 1,007 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2017 were as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,282 $ (1,282 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 304 — 304 Total derivative assets $ 1,586 $ (1,282 ) $ 304 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 11,497 $ (11,497 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 2,259 — 2,259 Total derivative liabilities $ 13,756 $ (11,497 ) $ 2,259 |
Fair Value Of Financial Instrum
Fair Value Of Financial Instruments: | 12 Months Ended |
Dec. 31, 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 10 , were as follows at December 31 (in thousands): 2018 2017 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 20,776 $ 20,776 $ 15,420 $ 15,420 Restricted cash and equivalents (a) $ 3,369 $ 3,369 $ 2,820 $ 2,820 Notes payable (b) $ 185,620 $ 185,620 $ 211,300 $ 211,300 Long-term debt, including current maturities (c) (d) $ 2,956,578 $ 3,039,108 $ 3,115,143 $ 3,350,544 _______________ (a) Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings. 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. Cash and Cash Equivalents Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal. Restricted Cash and Equivalents Restricted cash and cash equivalents represent restricted cash and uninsured term deposits. Notes Payable and Long-Term Debt For additional information on our notes payable and long-term debt, see Note 6 and Note 7 . |
Equity_
Equity: | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders' Equity Note [Abstract] | |
Equity | EQUITY Equity Units On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million . Each Equity Unit had a stated amount of $50.00 and consisted of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5% , undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on 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. See Note 6 for additional information. 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 were used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt. At-the-Market Equity Offering Program On August 4, 2017, we renewed the 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 year 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 under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017. During the twelve months ended December 31, 2016, we issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million , net of $1.2 million in commissions. Equity Compensation Plans` Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 800,180 shares available to grant at December 31, 2018 . Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2018 , total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands): 2018 2017 2016 Stock-based compensation expense $ 12,390 $ 7,626 $ 10,885 Stock Options The Company has not issued any stock options since 2014 and has 68,749 stock options outstanding at December 31, 2018 . The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements. Restricted Stock The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years , contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2018 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 267 $ 55.94 Granted 113 57.31 Vested (119 ) 54.24 Forfeited (25 ) 55.52 Balance at end of period 236 $ 57.50 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2018 $ 57.31 $ 6,776 2017 $ 60.63 $ 7,909 2016 $ 53.55 $ 4,602 As of December 31, 2018 , there was $8.9 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years . Performance Share Plan Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.8 million at December 31, 2018 would be reclassified as a liability. Outstanding performance periods at December 31 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2016 January 1, 2016 - December 31, 2018 51 0% 200% January 1, 2017 January 1, 2017 - December 31, 2019 49 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 53 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2018 (in thousands) (in thousands) Performance Shares balance at beginning of period 74 $ 55.31 74 Granted 28 61.82 28 Forfeited (3 ) 58.14 (3 ) Vested (22 ) 54.92 (22 ) Performance Shares balance at end of period 77 $ 57.66 77 $ 76.03 _____________________ (a) The grant date fair values for the performance shares granted in 2018 , 2017 and 2016 were determined by Monte Carlo simulation using a blended volatility of 21% , 23% and 24% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2018 $ 61.82 December 31, 2017 $ 63.52 December 31, 2016 $ 47.76 There were no performance plan payouts during the years ended December 31, 2018, 2017, and 2016. On January 29, 2019 , the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2016 through December 31, 2018 performance period was at the 74.8 percentile of its peer group and confirmed a payout equal to 161.9% of target shares, valued at $5.7 million . The payout was fully accrued at December 31, 2018 . As of December 31, 2018 , there was $3.2 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.8 years . Shareholder Dividend Reinvestment and Stock Purchase Plan We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2018 , there were 253,418 shares of unissued stock available for future offering under the plan. Preferred Stock Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. A partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Net income available for common stock for the years ended December 31, 2018 , 2017 and 2016 was reduced by $14 million , $14 million , and $10 million , respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments. Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31: 2018 2017 (in thousands) Assets Current assets $ 13,620 $ 14,837 Property, plant and equipment of variable interest entities, net $ 199,839 $ 208,595 Liabilities Current liabilities $ 5,174 $ 4,565 |
Regulatory Matters_
Regulatory Matters: | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
Regulatory Matters | REGULATORY MATTERS 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, was primarily from the change in the federal tax rate from 35% to 21% 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 $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 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 $ 2.2 million June 2018 Kansas $ 1.9 million April 2018 Nebraska $ 3.8 million July 2018 South Dakota $ 7.6 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. Excess Deferred Income Taxes As of December 31, 2018 and 2017 , we have a regulatory liability associated with TCJA related items of approximately $311 million and $301 million , respectively. The majority of this regulatory liability relates to excess deferred taxes resulting from the remeasurement of deferred tax assets and liabilities in 2017. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. See Note 15 for more information. Electric Utilities Regulatory Activity Corriedale Wind Project On December 17, 2018, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a new $57 million , 40 MW wind generation project near Cheyenne, Wyoming. If approved, the 40 MW Corriedale Wind Energy Project would be jointly owned by South Dakota Electric and Wyoming Electric. The project would be largely constructed and placed in service during 2020. Wyoming Electric Integrated Resource Plan On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019. Wyoming Electric Settlement On October 31, 2018, 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 a total of $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 December 31, 2018, we have recorded a liability of $6.0 million related to the PCA. South Dakota Electric Common Use System (CUS) The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year. South Dakota Electric Settlement On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a 6 -year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances as of the settlement date of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10 -year period ending September 30, 2024. The vegetation management regulatory asset as of the settlement date of $14 million , previously unamortized, is also being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million . The June 16, 2017 settlement had no impact to base rates. Gas Utilities Regulatory Activity Colorado Gas On October 10, 2018, we received approval from the CPUC for a request to consolidate our Colorado gas utility operations into a new utility entity. The Colorado portion of Black Hills Gas Distribution, LLC, will be combined with Black Hills/Colorado Gas Utility Company, Inc., into a new company named Black Hills Colorado Gas, Inc. The two companies being merged currently serve 187,000 Colorado customers doing business as Black Hills Energy. On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity. Wyoming Gas On November 20, 2018, we received approval from the WPSC for a CPCN to construct a new $54 million , 35 -mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be placed in service in late 2019. 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 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. Kansas Gas On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $0.6 million based on inclusion of approximately $8.0 million of eligible capital investments under the Gas System Reliability Rider. The Kansas Legislature passed legislation in 2018 enabling the annual eligible investments to double from approximately $8.0 million to $16 million effective January 1, 2019. RMNG In Colorado, new rates for RMNG went into effect June 1, 2018 after we reached a settlement which was approved by the CPUC. 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. 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 NPSC 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. On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million , which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018. |
Operating Leases_
Operating Leases: | 12 Months Ended |
Dec. 31, 2018 | |
Leases, Operating [Abstract] | |
Operating Leases | OPERATING LEASES We have entered into lease agreements for office facilities, communication tower sites, land and equipment. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands): 2018 2017 2016 Rent expense (a) $ 2,667 $ 10,325 $ 9,568 _______________ (a) The decrease in rent expense is primarily driven by current year expiration of office leases and by purchases of facilities previously leased. The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2019 $ 1,052 2020 $ 464 2021 $ 344 2022 $ 224 2023 $ 216 Thereafter $ 1,776 |
Income Taxes_
Income Taxes: | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES TCJA 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% . As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. 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 rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million . Of the $309 million , approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. Tax benefit related to legal entity 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 and December 31, 2018. As a result of these transactions, additional deferred income tax assets of $73 million , related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the 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. Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2018 2017 2016 Current: Federal $ 325 $ (6,193 ) $ (21,806 ) State 247 (1,432 ) (1,797 ) 572 (7,625 ) (23,603 ) Deferred: Federal (23,295 ) 76,567 78,997 State 815 4,470 3,759 Excess deferred tax amortization (1,727 ) — — Tax credit amortization (32 ) (45 ) (52 ) (24,239 ) 80,992 82,704 $ (23,667 ) $ 73,367 $ 59,101 Included in discontinued operations is a tax benefit of $2.6 million , $8.4 million and $49 million for 2018 , 2017 and 2016 , respectively. The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2018 2017 Deferred tax assets: Regulatory liabilities $ 92,966 $ 90,742 Employee benefits 14,039 18,724 Federal net operating loss 139,371 155,276 Other deferred tax assets (a) 101,579 74,561 Less: Valuation allowance (11,809 ) (9,121 ) Total deferred tax assets 336,146 330,182 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (529,338 ) (510,774 ) Regulatory assets (32,324 ) (26,245 ) Goodwill (b) (602 ) (46,392 ) State deferred tax liability (64,095 ) (58,930 ) Deferred costs (13,351 ) (16,063 ) Other deferred tax liabilities (7,767 ) (8,298 ) Total deferred tax liabilities (647,477 ) (666,702 ) Net deferred tax liability $ (311,331 ) $ (336,520 ) _______________ (a) Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) Legal entity restructuring - see above. The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2018 2017 2016 Federal statutory rate 21.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 2.3 0.9 1.2 Percentage depletion (0.4 ) (0.6 ) (0.8 ) Non-controlling interest (a) (1.3 ) (1.8 ) (1.6 ) Equity AFUDC — (0.2 ) (0.5 ) Tax credits (2.0 ) (1.7 ) (0.4 ) Transaction costs — — 0.5 Accounting for uncertain tax positions adjustment — (0.2 ) (2.7 ) Flow-through adjustments (b) (1.6 ) (1.1 ) (2.1 ) Jurisdictional simplification project (d) (28.5 ) — — Other tax differences (0.4 ) (0.9 ) 0.1 IRC 172(f) carryback claim — (0.7 ) — TCJA corporate rate reduction (c) 1.6 (2.7 ) — (9.3 )% 26.0 % 28.7 % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (c) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded approximately $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded approximately $8.0 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (d) Legal entity restructuring - see above. At December 31, 2018 , we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 663,741 2021 to 2038 State Net Operating Loss Carryforward $ 542,632 2019 to 2038 As of December 31, 2018 , we had a $0.4 million valuation allowance against the state NOL carryforwards. Our 2018 analysis of the ability to utilize such NOLs resulted in a $0.4 million increase in the valuation allowance offset by a $1.2 million decrease from expired NOL. This resulted in an increase to tax expense of $0.4 million and a decrease to the state NOL carryforward of $1.2 million . The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2018. This projected decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years . In certain states, the carryforward period is limited to 5 years . Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense. The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2016 $ 31,986 Additions for prior year tax positions 2,423 Reductions for prior year tax positions (19,174 ) Additions for current year tax positions — Settlements (11,643 ) Ending balance at December 31, 2016 3,592 Additions for prior year tax positions 358 Reductions for prior year tax positions (5,713 ) Additions for current year tax positions 5,026 Settlements — Ending balance at December 31, 2017 3,263 Additions for prior year tax positions 251 Reductions for prior year tax positions (417 ) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 $ 3,583 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.1 million . We recognized no interest expense associated with income taxes for the years ended December 31, 2018 , December 31, 2017 and December 31, 2016 . We had no accrued interest (before tax effect) associated with income taxes at December 31, 2018 and December 31, 2017 . The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which files a separate consolidated tax return from Black Hills Corporation and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. Black Hills Corporation is no longer subject to examination for tax years prior to 2015. We had deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. In 2016, the settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable. As of December 31, 2018 , we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2019 . State tax credits have been generated and are available to offset future state income taxes. At December 31, 2018 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 20,285 2023 to 2036 Research and development $ 180 No expiration As of December 31, 2018 , we had an $11 million valuation allowance against the state tax credit carryforwards. Our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.5 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.6 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2018. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense. |
Other Comprehensive Income_
Other Comprehensive Income: | 12 Months Ended |
Dec. 31, 2018 | |
Statement of Comprehensive Income [Abstract] | |
Other Comprehensive Income | OTHER COMPREHENSIVE INCOME 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 Consolidated Statements of Income (Loss) for the period, net of tax (in thousands): Location on the Consolidated Statements of Income (Loss) Amount Reclassified from AOCI December 31, 2018 December 31, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851 ) $ (2,941 ) Commodity contracts Net (loss) from discontinued operations — 913 Commodity contracts Fuel, purchased power and cost of natural gas sold (130 ) (243 ) (2,981 ) (2,271 ) Income tax Income tax benefit (expense) 630 875 Total reclassification adjustments related to cash flow hedges, net of tax $ (2,351 ) $ (1,396 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 178 $ 168 Prior service cost Net (loss) from discontinued operations — 29 Actuarial gain (loss) Operations and maintenance (2,487 ) (1,599 ) Actuarial gain (loss) Net (loss) from discontinued operations — (58 ) (2,309 ) (1,460 ) Income tax Income tax benefit (expense) 543 (516 ) Total reclassification adjustments related to defined benefit plans, net of tax (1,766 ) (1,976 ) Total reclassifications $ (4,117 ) $ (3,372 ) Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges 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 — 755 2,155 2,910 Amounts reclassified from AOCI 2,252 99 1,766 4,117 Reclassification to regulatory asset — — 6,519 6,519 Reclassification of certain tax effects from AOCI 22 (8 ) 726 740 As of December 31, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 231 (1,890 ) (1,659 ) Amounts reclassified from AOCI 1,912 (516 ) 944 2,340 Reclassification of certain tax effects from AOCI (3,384 ) — (3,616 ) (7,000 ) As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash flow Information: | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Years ended December 31, 2018 2017 2016 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 69,017 $ 28,191 $ 27,034 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 2,625 $ 3,198 $ 8,577 Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (137,965 ) $ (132,428 ) $ (113,627 ) Income taxes (paid) refunded $ (14,730 ) $ 1,775 $ (1,156 ) |
Employee Benefit Plans_
Employee Benefit Plans: | 12 Months Ended |
Dec. 31, 2018 | |
Defined Benefit Plan [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company. The SourceGas Retirement Savings Plan was merged into the Black Hills Corporation Retirement Savings Plan effective December 31, 2017. The plan design of the Black Hills Corporation 401(k) Plan applies to all eligible employees as of January 1, 2018. Defined Benefit Pension Plan (Pension Plan) We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria. The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2018 , the expected rate of return on pension plan assets was based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2018 2017 Equity 17% 26% Real estate 4 4 Fixed income 71 63 Cash 3 1 Hedge funds 5 6 Total 100% 100% Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company. Plan Assets We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plans BHC sponsors retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans for participating business units are pre-funded via VEBAs. Pre-65 retirees as well as a grandfathered group of post-65 Cheyenne Light, Fuel and Power (“CLFP”) retirees and a grandfathered group of post-65 former SourceGas employees who retired prior to January 1, 2017 receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHC and Black Hills Utility Holdings retirees is provided through an individual market healthcare exchange. Medicare-eligible SourceGas employees who retired after December 31, 2016 also receive retiree medical coverage through an individual market healthcare exchange. Plan Assets We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provide for partial pre-funding via VEBAs and a Grantor Trust. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Kansas and Iowa. We do not pre-fund the Healthcare Plans for those employees outside Arkansas, Kansas and Iowa. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands): 2018 2017 Defined Contribution Plan Company retirement contribution $ 8,766 $ 10,223 Matching contributions $ 13,559 $ 9,811 2018 2017 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 27,700 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 5,298 $ 4,332 Supplemental Non-Qualified Defined Benefit Plans $ 2,073 $ 3,217 While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2019 . Fair Value Measurements Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,867 $ — $ 1,867 $ — $ 1,867 Common Collective Trust - Cash and Cash Equivalents — 9,923 — 9,923 — 9,923 Common Collective Trust - Equity — 67,457 — 67,457 — 67,457 Common Collective Trust - Fixed Income — 279,148 — 279,148 — 279,148 Common Collective Trust - Real Estate — 67 — 67 13,551 13,618 Hedge Funds — — — — 18,783 18,783 Total investments measured at fair value $ — $ 358,462 $ — $ 358,462 $ 32,334 $ 390,796 Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,280 $ — $ 1,280 $ — $ 1,280 Common Collective Trust - Cash and Cash Equivalents — 2,184 — 2,184 — 2,184 Common Collective Trust - Equity — 109,496 — 109,496 — 109,496 Common Collective Trust - Fixed Income — 262,329 — 262,329 — 262,329 Common Collective Trust - Real Estate — 1,728 — 1,728 15,701 17,429 Hedge Funds — — — — 23,625 23,625 Total investments measured at fair value $ — $ 377,017 $ — $ 377,017 $ 39,326 $ 416,343 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,873 $ — $ — $ 4,873 $ — $ 4,873 Equity Securities 1,005 — — 1,005 — 1,005 Intermediate-term Bond — 2,284 — 2,284 — 2,284 Total investments measured at fair value $ 5,878 $ 2,284 $ — $ 8,162 $ — $ 8,162 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,671 $ — $ — $ 4,671 $ — $ 4,671 Equity Securities 1,374 — — 1,374 — 1,374 Intermediate-term Bond — 2,576 — 2,576 — 2,576 Total investments measured at fair value $ 6,045 $ 2,576 $ — $ 8,621 $ — $ 8,621 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2. AXA Equitable General Fixed Income Fund : This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2. Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. Common Collective Trust-Real Estate Fund : This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Common Collective Trust-Real Estate Fund : This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 20% of the shares may be redeemed at the end of each month with a 10 -day notice and full redemptions are available at the end of each quarter with 45 -day notice, and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI: Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31 (in thousands), 2018 2017 2018 2017 2018 2017 Change in benefit obligation: Projected benefit obligation at beginning of year $ 474,725 $ 440,179 $ 45,112 $ 43,869 $ 69,339 $ 68,023 Service cost 6,834 7,034 1,764 2,937 2,291 2,300 Interest cost 15,470 15,520 1,170 1,276 2,085 2,141 Actuarial (gain) loss (31,340 ) 36,661 (2,963 ) 247 (9,045 ) (396 ) Amendments — — — — — 265 Benefits paid (20,308 ) (24,669 ) (2,073 ) (3,217 ) (5,298 ) (4,332 ) Plan participants’ contributions — — — — 1,445 1,338 Projected benefit obligation at end of year $ 445,381 $ 474,725 $ 43,010 $ 45,112 $ 60,817 $ 69,339 Employee Benefit Plan Assets Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans (a) As of December 31 (in thousands), 2018 2017 2018 2017 2018 2017 Change in fair value of plan assets: Beginning fair value of plan assets $ 416,343 $ 364,695 $ — $ — $ 8,621 $ 8,470 Investment income (loss) (17,939 ) 48,617 — — (149 ) 120 Employer contributions 12,700 27,700 2,073 3,217 3,543 3,025 Retiree contributions — — — — 1,445 1,338 Benefits paid (20,308 ) (24,669 ) (2,073 ) (3,217 ) (5,298 ) (4,332 ) Ending fair value of plan assets $ 390,796 $ 416,343 $ — $ — $ 8,162 $ 8,621 ____________________ (a) Assets of VEBAs and Grantor Trust. The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2018 2017 2018 2017 Regulatory assets $ 82,919 $ 72,756 $ — $ — $ 6,655 $ 11,507 Current liabilities $ — $ — $ 1,463 $ 1,372 $ 3,885 $ 4,423 Non-current assets $ — $ — $ — $ — $ 249 $ 69 Non-current liabilities $ 54,585 $ 58,381 $ 41,547 $ 43,739 $ 49,015 $ 56,365 Regulatory liabilities $ 4,620 $ 5,232 $ — $ — $ 5,207 $ 3,334 Accumulated Benefit Obligation Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31 (in thousands) 2018 2017 2018 2017 2018 2017 Accumulated Benefit Obligation $ 428,851 $ 450,394 $ 40,530 $ 41,243 $ 60,817 $ 69,339 Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2016 2018 2017 2016 2018 2017 2016 Service cost $ 6,834 $ 7,034 $ 7,619 $ 1,764 $ 1,546 $ 1,335 $ 2,291 $ 2,300 $ 1,757 Interest cost 15,470 15,520 15,743 1,170 1,276 1,257 2,085 2,141 1,942 Expected return on assets (24,741 ) (24,517 ) (23,062 ) — — — (315 ) (315 ) (279 ) Net amortization of prior service cost 58 58 58 2 2 2 (398 ) (411 ) (428 ) Recognized net actuarial loss (gain) 8,632 4,007 7,173 1,000 1,001 829 216 499 335 Settlement expense (a) — — 10 — — — — — Net periodic expense $ 6,253 $ 2,102 $ 7,541 $ 3,936 $ 3,825 $ 3,423 $ 3,879 $ 4,214 $ 3,327 ____________________ (a) Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year. For the year ended December 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense, on the Consolidated Statements of Income. For the years ended December 31, 2017 and 2016, 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 Consolidated Statements of Income. See Note 1 for additional information. AOCI For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2018 2017 2018 2017 Net (gain) loss $ 11,967 $ 10,056 $ 4,668 $ 6,639 $ 860 $ 1,309 Prior service cost (gain) 1 21 3 4 (317 ) (542 ) Reclassification of certain tax effects from AOCI (594 ) 2,087 (87 ) 1,371 (45 ) 158 Reclassification to regulatory asset (5,600 ) — — — (919 ) — Total AOCI $ 5,774 $ 12,164 $ 4,584 $ 8,014 $ (421 ) $ 925 Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate 4.40 % 3.71 % 4.27 % 4.34 % 3.56 % 4.02 % 4.28 % 3.60 % 3.96 % Rate of increase in compensation levels 3.52 % 3.43 % 3.47 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate (a) 3.71 % 4.27 % 4.50 % 3.67 % 4.02 % 4.28 % 3.60 % 4.05 % 4.18 % Expected long-term rate of return on assets (b) 6.25 % 6.75 % 6.87 % N/A N/A N/A 3.93 % 3.88 % 3.83 % Rate of increase in compensation levels 3.43 % 3.47 % 3.42 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs. (b) The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: 2018 2017 Trend Rate - Medical Pre-65 for next year - All Plans 6.70% 7.00% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.94% 5.00% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2026 2026 Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details. The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans 2019 $ 24,405 $ 1,463 $ 4,898 2020 $ 25,847 $ 1,406 $ 5,545 2021 $ 26,951 $ 1,617 $ 5,695 2022 $ 27,972 $ 1,727 $ 5,849 2023 $ 29,002 $ 1,912 $ 5,607 2024-2028 $ 151,915 $ 12,208 $ 24,953 |
Commitments And Contingencies_
Commitments And Contingencies: | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Power Purchase and Transmission Services Agreements Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties: • Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20 -year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit. • South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023 , for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. • South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023 . The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. • Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028 , provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric. • Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029 , provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric. • South Dakota Electric’s PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029 . Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2018 2017 2016 PPA with PacifiCorp $ 13,681 $ 13,218 $ 12,221 Transmission services agreement with PacifiCorp $ 1,742 $ 1,671 $ 1,428 PPA with Happy Jack $ 3,884 $ 3,846 $ 3,836 PPA with Silver Sage $ 5,376 $ 4,934 $ 4,949 Busch Ranch I Wind Farm (a) $ — $ 1,966 $ 2,071 PPA with Platte River Power Authority $ 223 $ — $ — PPAs with Cargill (b) $ — $ — $ 10,995 ________________ (a) On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I Wind Farm from AltaGas. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm. (b) PPAs with Cargill expired on December 31, 2016. Power Purchase Agreement - Related Party On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas. Black Hills Electric Generation will provide its 14.5 MW share of energy from the wind farm to Colorado Electric through a new PPA that replaces the PPA that Colorado Electric had with AltaGas, expiring in October 2037 . Other Gas Supply Agreements Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044 . Purchase Commitments We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract. Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days . At December 31, 2018 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): CIG Rockies NNG-Ventura NWPL-Wyoming Other 2019 5,803,117 3,650,000 720,000 236 2020 75,075 3,660,000 0 0 2021 0 3,650,000 0 0 2022 0 1,810,000 0 0 2023 0 0 0 0 Thereafter 0 0 0 0 Purchases under these contracts totaled $27 million , $65 million and $31 million for 2018 , 2017 and 2016 , respectively. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation and storage agreements 2019 $ 22,092 $ 129,018 2020 $ 6,837 $ 127,326 2021 $ 6,203 $ 118,707 2022 $ 6,203 $ 92,635 2023 $ 6,204 $ 73,919 Thereafter $ — $ 148,363 Future Purchase Agreement - Related Party Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022 , includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.1 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35 -year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties: • During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023 . • South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023 . • During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019 , South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. • South Dakota Electric has a PPA with MEAN expiring May 31, 2028 . This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. • South Dakota Electric has an agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals. Related Party Lease Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031 , provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations. Reimbursement Agreement We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021 . In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. Environmental Matters We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Solid Waste Disposal Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date. Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Reclamation Liability For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its land lease for Busch Ranch I, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. See Note 8 for additional information. Manufactured Gas Processing As a result of the Aquila Transaction, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.0 million regulatory asset for manufactured gas processing sites; see Note 1. As of December 31, 2018 , our estimated liabilities for Iowa’s MGP site currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2018 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties. For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities. |
Guarantees_
Guarantees: | 12 Months Ended |
Dec. 31, 2018 | |
Guarantees [Abstract] | |
Guarantees | GUARANTEES We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2018 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 54,683 Ongoing Contract performance guarantee (b) 39,807 December 2019 $ 94,490 _______________________ (a) We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. (b) BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made. |
Discontinued Operations_
Discontinued Operations: | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | DISCONTINUED OPERATIONS Results of operations for discontinued operations have been classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Current assets and current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our 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 December 31, 2018, we have sold our oil and gas properties and completed the exit of the Oil and Gas business. In 2017, 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 fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale were reasonable based on the information that was known when the estimates were made. 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 adjustments made to the fair value of our held for sale liabilities. For the year ended December 31, 2018, we recorded $3.3 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 BHEP at December 31, 2017 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the final disposals occurring in 2018. As of (in thousands) December 31, 2017 Other current assets $ 10,360 Deferred income tax assets, noncurrent, net 16,966 Property, plant and equipment, net 56,916 Other current liabilities (18,966 ) Other noncurrent liabilities (22,808 ) Net assets $ 42,468 At December 31, 2017, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties. BHEP’s Other current liabilities at December 31, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 consisted primarily of ARO obligations relating to plugging and abandonment of oil and gas wells. Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands): For the Years Ended December 31, 2018 December 31, 2017 December 31, 2016 Revenue $ 5,897 $ 25,382 $ 34,058 Operations and maintenance 11,014 22,872 27,187 Loss on sale of assets 3,259 — — Depreciation, depletion and amortization 1,300 7,521 13,510 Impairment of long-lived assets — 20,385 106,957 Total operating expenses 15,573 50,778 147,654 Operating (loss) (9,676 ) (25,396 ) (113,596 ) Interest income (expense), net (19 ) 181 698 Other income (expense), net 190 (297 ) 110 Income tax benefit 2,618 8,413 48,626 (Loss) from discontinued operations $ (6,887 ) $ (17,099 ) $ (64,162 ) Full Cost Accounting Historically, we used the full cost method of accounting for oil and gas production activities. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. Impairment of long-lived assets As discussed above, at December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a write down of $20 million . There were no adjustments made to the fair value of our held for sale liabilities. As a result of continued low commodity prices throughout 2016, we recorded non-cash ceiling test impairments of our Oil and Gas assets totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead. During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million , in addition to the ceiling test impairments noted above. |
Oil and Gas Reserves (Unaudited
Oil and Gas Reserves (Unaudited): | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Reserves (Unaudited) | OIL AND GAS RESERVES (Unaudited) On November 1, 2017, we initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. On November 1, 2017, we stopped the use of the full-cost method of accounting for our oil and gas business. The assets and liabilities have been classified as held for sale and the results of operations are included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As a result, our oil and gas reserves were no longer considered significant in 2017. Oil and Gas reserves were considered significant in 2016. For more information, see Note 21 . Costs Incurred Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands): 2016 Acquisition of properties: Proved $ — Unproved 910 Exploration costs 1,102 Development costs 4,657 Asset retirement obligations incurred — Total costs incurred $ 6,669 Reserves The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding. 2016 Oil Gas NGL (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 3,450 73,412 1,752 Production (a) (319 ) (9,430 ) (133 ) Sales (570 ) (1,291 ) (17 ) Additions - extensions and discoveries 3 52 — Revisions to previous estimates (322 ) (8,173 ) 110 Balance at end of year 2,242 54,570 1,712 Proved developed reserves at end of year included above 2,242 54,570 1,712 Proved undeveloped reserves at the end of year included in above — — — NYMEX prices $ 42.75 $ 2.48 $ — Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 ________________________ (a) Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production. (c) For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54 /Mcf for Piceance, $0.92 /Mcf for San Juan and $0.53 /Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable. Capitalized Costs Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2016 Unproved oil and gas properties $ 18,547 Proved oil and gas properties 1,043,558 Gross capitalized costs 1,062,105 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) Net capitalized costs $ 62,014 Results of Operations For more on oil and gas producing activities included in discontinued operations, see Note 21. Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2016 Revenue $ 34,058 Production costs 17,231 Depreciation, depletion and amortization 12,574 Impairment of long-lived assets 106,957 Total costs 136,762 Results of operations from producing activities before tax (102,704 ) Income tax benefit (expense) 37,916 Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) Unproved Properties Unproved properties not subject to amortization at December 31, 2016 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million of interest during 2016 on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands): 2016 Leasehold acquisition cost $ 963 Exploration cost 532 Capitalized interest 50 Total $ 1,545 Standardized Measure of Discounted Future Net Cash Flows Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands): 2016 Future cash inflows $ 246,221 Future production costs (166,248 ) Future development costs, including plugging and abandonment (18,333 ) Future net cash flows 61,640 10% annual discount for estimated timing of cash flows (26,574 ) Standardized measure of discounted future net cash flows $ 35,066 The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands): 2016 Standardized measure - beginning of year $ 79,028 Sales and transfers of oil and gas produced, net of production costs (4,314 ) Net changes in prices and production costs (32,698 ) Changes in future development costs 1,825 Revisions of previous quantity estimates (7,477 ) Accretion of discount 7,903 Sales of reserves (9,201 ) Standardized measure - end of year $ 35,066 Changes in the standardized measure from “revisions of previous quantity estimates” were driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications were generally made at the well level each year through the reserve review process. These production profile modifications were based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments were reviewed each year and were often modified in response to current market conditions for items such as permitting and service availability. |
Quarterly Historical Data (Unau
Quarterly Historical Data (Unaudited): | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Historical Data (Unaudited) | QUARTERLY HISTORICAL DATA (Unaudited) The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2018 and 2017 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2018 Revenue $ 575,389 $ 355,704 $ 321,979 $ 501,196 Operating income (loss) $ 148,274 $ 69,551 $ 65,085 $ 114,127 Income (loss) from continuing operations $ 138,977 $ 27,167 $ 21,801 $ 91,604 Income (loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income attributable to noncontrolling interest $ (3,630 ) $ (2,823 ) $ (3,994 ) $ (3,773 ) Net income (loss) available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Amounts attributable to common shareholders: Net income (loss) from continuing operations $ 135,347 $ 24,344 $ 17,807 $ 87,831 Net income (loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income (loss) available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Income (loss) per share for continuing operations - Basic $ 2.54 $ 0.46 $ 0.33 $ 1.52 Income (loss) per share for discontinued operations - Basic $ (0.05 ) $ (0.05 ) $ (0.02 ) $ (0.02 ) Earnings (loss) per share - Basic $ 2.49 $ 0.41 $ 0.32 $ 1.50 Income (loss) per share for continuing operations - Diluted $ 2.50 $ 0.45 $ 0.32 $ 1.51 Income (loss) per share for discontinued operations - Diluted $ (0.04 ) $ (0.05 ) $ (0.02 ) $ (0.02 ) Earnings (loss) per share - Diluted 2.46 0.40 0.31 1.49 Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million , respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2017 Revenue $ 547,528 $ 341,829 $ 335,611 $ 455,298 Operating income (loss) $ 150,186 $ 69,796 $ 79,559 $ 117,195 Income (loss) from continuing operations $ 81,715 $ 25,927 $ 32,898 $ 67,835 Income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income attributable to noncontrolling interest $ (3,623 ) $ (3,116 ) $ (3,935 ) $ (3,568 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Amounts attributable to common shareholders: Net income (loss) from continuing operations 78,092 22,811 28,963 64,267 Net income (loss) from discontinued operations (1,569 ) (616 ) (1,300 ) (13,614 ) Net income (loss) available for common stock 76,523 22,195 27,663 50,653 Income (loss) per share for continuing operations - Basic $ 1.47 $ 0.43 $ 0.54 $ 1.21 Income (loss) per share for discontinued operations - Basic (0.03 ) (0.01 ) (0.02 ) (0.26 ) Earnings (loss) per share - Basic $ 1.44 $ 0.42 $ 0.52 $ 0.95 Income (loss) per share for continuing operations - Diluted $ 1.42 $ 0.41 $ 0.52 $ 1.17 Income (loss) per share for discontinued operations - Diluted (0.03 ) (0.01 ) (0.02 ) (0.25 ) Earnings (loss) per share - Diluted $ 1.39 $ 0.40 $ 0.50 $ 0.92 Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13 million . |
Business Description (Policies)
Business Description (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business Description | Segment Reporting 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. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. All of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21 . |
Use of Estimates and Basis of Presentation | Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information. |
Variable Interest Entities | Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12 . |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as 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 and cash equivalents. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. |
Revenue Recognition | Revenue Recognition Revenue is 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. 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 Gas and Electric Utilities 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 year ended December 31, 2018 . Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194 ) $ 1,461,317 Transportation — 140,705 — — (1,348 ) 139,357 Wholesale 33,687 — 52,396 — (46,562 ) 39,521 Market - off-system sales 24,799 866 — — (8,102 ) 17,563 Transmission/Other 56,209 49,402 — — (14,827 ) 90,784 Revenue from contracts with customers 709,024 1,024,352 52,396 65,803 (103,033 ) 1,748,542 Other revenues 2,427 955 36,556 2,230 (36,442 ) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 88,952 $ 68,033 $ (139,475 ) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194 ) $ 33,609 Services transferred over time 709,024 1,024,352 52,396 — (70,839 ) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 52,396 $ 65,803 $ (103,033 ) $ 1,748,542 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 table 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 Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Black Hills 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 $37 million during the year ended December 31, 2018. As of December 31, 2018 , $19 million has been returned to customers and approximately $18 million remains in reserve as a current regulatory liability. Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. 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 above. 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. |
Materials, Supplies and Fuel | Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. |
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. 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 December 31, 2018. |
Property, Plant and Equipment | Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. |
Goodwill and Intangible Assets | Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. |
Asset Retirement Obligations | Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. |
Fair Value Measurements | Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not have any Level 3 investments. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. |
Regulatory Accounting | Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. We had the following regulatory assets and liabilities as of December 31 (in thousands): 2018 2017 Regulatory assets Deferred energy and fuel cost adjustments - current (a) $ 29,661 $ 20,187 Deferred gas cost adjustments (a) 3,362 31,844 Gas price derivatives (a) 6,201 11,935 Deferred taxes on AFUDC (b) 7,841 7,847 Employee benefit plans (c) 110,524 109,235 Environmental (a) 959 1,031 Asset retirement obligations (a) 529 517 Loss on reacquired debt (a) 21,001 20,667 Renewable energy standard adjustment (a) 1,722 1,088 Deferred taxes on flow through accounting (c) 31,044 26,978 Decommissioning costs 11,700 13,287 Gas supply contract termination (a) 14,310 20,001 Other regulatory assets (a) 45,381 32,837 Total regulatory assets 284,235 297,454 Less current regulatory assets (48,776 ) (81,016 ) Regulatory assets, non-current $ 235,459 $ 216,438 Regulatory liabilities Deferred energy and gas costs (a) $ 6,991 $ 3,427 Employee benefit plan costs and related deferred taxes (c) 42,533 40,629 Cost of removal (a) 150,123 130,932 Excess deferred income taxes (c) 310,562 301,553 TCJA revenue reserve 18,032 — Other regulatory liabilities (c) 12,553 8,585 Total regulatory liabilities 540,794 485,126 Less current regulatory liabilities (29,810 ) (6,832 ) Regulatory liabilities, non-current $ 510,984 $ 478,294 __________ (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. Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2018 are hedged over a maximum forward term of 2 years . Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI, including costs being amortized from the Aquila and SourceGas Transactions. Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown. Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years . We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. Revenue Subject to Refund - Revenue subject to refund at December 31, 2018 represent revenue reserved as a result of the TCJA. See above “ TCJA Revenue Reserve” under Revenue recognition for further disclosure. |
Income Taxes | Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21% . See Notes 13 and 15 for additional information. It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. |
Earnings per Share of Common Stock | Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. |
Business Combinations | Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. |
Noncontrolling Interest | Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. |
Share-Based Compensation | Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. |
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 original 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 adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted 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 elected the “package of three” practical expedient. We have implemented a new lease accounting system and adjusted related procedures and controls accordingly. On January 1, 2019, we will record an operating lease right of use asset and an off-setting operating lease obligation liability of approximately $3.2 million . Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement 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 have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment 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 guidance 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 1. 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 year ended December 31, 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. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, ASU 2018-02 In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issued to address industry concerns regarding the application of current accounting guidance to certain provisions of the new tax reform legislation. This ASU permits entities to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted. We have implemented this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting . This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. |
Business Description (Tables)
Business Description (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Accounts Receivable and Allowance for Doubtful Accounts | Following is a summary of accounts receivable as of December 31 (in thousands): 2018 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,721 $ 35,125 $ (448 ) $ 74,398 Gas Utilities 96,123 90,521 (2,592 ) 184,052 Power Generation 1,876 — — 1,876 Mining 3,988 — — 3,988 Corporate 5,008 — (169 ) 4,839 Total $ 146,716 $ 125,646 $ (3,209 ) $ 269,153 2017 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts 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 |
Schedule of Valuation and Qualifying Accounts Disclosure | Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Adjustments (a) Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2018 $ 3,081 $ — $ 6,859 $ 4,092 $ (10,823 ) $ 3,209 2017 $ 2,392 $ — $ 4,926 $ 8,262 $ (12,499 ) $ 3,081 2016 $ 1,741 $ 2,158 $ 2,704 $ 4,915 $ (9,126 ) $ 2,392 ________________ (a) Represents allowance balances added with the SourceGas acquisition. |
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 year ended December 31, 2018 . Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194 ) $ 1,461,317 Transportation — 140,705 — — (1,348 ) 139,357 Wholesale 33,687 — 52,396 — (46,562 ) 39,521 Market - off-system sales 24,799 866 — — (8,102 ) 17,563 Transmission/Other 56,209 49,402 — — (14,827 ) 90,784 Revenue from contracts with customers 709,024 1,024,352 52,396 65,803 (103,033 ) 1,748,542 Other revenues 2,427 955 36,556 2,230 (36,442 ) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 88,952 $ 68,033 $ (139,475 ) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194 ) $ 33,609 Services transferred over time 709,024 1,024,352 52,396 — (70,839 ) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 52,396 $ 65,803 $ (103,033 ) $ 1,748,542 |
Materials, Supplies and Fuel | The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2018 2017 Materials and supplies $ 75,081 $ 69,732 Fuel - Electric Utilities 2,850 2,962 Natural gas in storage 39,368 40,589 Total materials, supplies and fuel $ 117,299 $ 113,283 |
Investments | The following table presents the carrying value of our investments (in thousands) as of December 31: 2018 2017 Cost method investment $ 28,201 $ — Cash surrender value of life insurance contracts 12,812 13,090 Total investments $ 41,013 $ 13,090 |
Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2018 2017 Accrued employee compensation, benefits and withholdings $ 63,742 $ 52,467 Accrued property taxes 42,510 42,029 Customer deposits and prepayments 43,574 44,420 Accrued interest 31,759 33,822 CIAC current portion 1,485 1,552 Other (none of which is individually significant) 32,431 45,172 Total accrued liabilities $ 215,501 $ 219,462 |
Goodwill | Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2017 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2018 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 |
Intangible Assets | Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2018 2017 2016 Intangible assets, net, beginning balance $ 7,559 $ 8,392 $ 3,380 Additions (a) 7,602 — 5,522 Amortization expense (b) (824 ) (833 ) (510 ) Intangible assets, net, ending balance $ 14,337 $ 7,559 $ 8,392 _________________ (a) The 2018 addition is related to the Busch Ranch 1 Wind Farm contract intangible asset. See Note 4 for further information. (b) Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years. |
Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities as of December 31 (in thousands): 2018 2017 Regulatory assets Deferred energy and fuel cost adjustments - current (a) $ 29,661 $ 20,187 Deferred gas cost adjustments (a) 3,362 31,844 Gas price derivatives (a) 6,201 11,935 Deferred taxes on AFUDC (b) 7,841 7,847 Employee benefit plans (c) 110,524 109,235 Environmental (a) 959 1,031 Asset retirement obligations (a) 529 517 Loss on reacquired debt (a) 21,001 20,667 Renewable energy standard adjustment (a) 1,722 1,088 Deferred taxes on flow through accounting (c) 31,044 26,978 Decommissioning costs 11,700 13,287 Gas supply contract termination (a) 14,310 20,001 Other regulatory assets (a) 45,381 32,837 Total regulatory assets 284,235 297,454 Less current regulatory assets (48,776 ) (81,016 ) Regulatory assets, non-current $ 235,459 $ 216,438 Regulatory liabilities Deferred energy and gas costs (a) $ 6,991 $ 3,427 Employee benefit plan costs and related deferred taxes (c) 42,533 40,629 Cost of removal (a) 150,123 130,932 Excess deferred income taxes (c) 310,562 301,553 TCJA revenue reserve 18,032 — Other regulatory liabilities (c) 12,553 8,585 Total regulatory liabilities 540,794 485,126 Less current regulatory liabilities (29,810 ) (6,832 ) Regulatory liabilities, non-current $ 510,984 $ 478,294 __________ (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. |
Earnings Per Share of Common Stock | A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands): 2018 2017 2016 Net income (loss) available for common stock $ 258,442 $ 177,034 $ 72,970 Weighted average shares - basic 54,420 53,221 51,922 Dilutive effect of: Equity Units 898 1,783 1,222 Equity compensation 168 116 127 Weighted average shares - diluted 55,486 55,120 53,271 Net income (loss) available for common stock, per share - Diluted $ 4.66 $ 3.21 $ 1.37 |
Antidilutive Securities | The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive for the years ended December 31 (in thousands): 2018 2017 2016 Equity compensation 16 11 3 Anti-dilutive shares excluded from computation of earnings (loss) per share 16 11 3 |
Acquisition (Tables)
Acquisition (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Final Purchase Price Allocation of Fair Value of Assets Acquired and Liabilities Assumed | (in thousands) Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration paid, net of working capital adjustment received $ 1,124,238 Allocation of Purchase Price: Current Assets $ 112,983 Property, plant & equipment, net 1,058,093 Goodwill 939,695 Deferred charges and other assets, excluding goodwill 133,299 Current liabilities (172,454 ) Long-term debt (758,874 ) Deferred credits and other liabilities (188,504 ) Total consideration paid, net of working-capital adjustment received $ 1,124,238 |
Schedule of Pro Forma Results | The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2016: Pro Forma Results December 31, 2016 (in thousands, except per share amounts) Revenue $ 1,617,878 Income from continuing operations $ 177,040 Net income (loss) $ 112,878 Earnings from continuing operations per share, Basic $ 3.41 Earnings from continuing operations per share, Diluted $ 3.32 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2018 2017 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,318,643 41 $ 1,315,044 39 32 46 Electric transmission 437,082 51 407,203 51 48 53 Electric distribution 793,725 48 755,213 48 45 50 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 233,531 28 232,842 31 26 28 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 3,049,292 2,976,613 Construction work in progress 60,480 13,595 Total electric plant 3,109,772 2,990,208 Less accumulated depreciation and amortization 706,869 644,022 Electric plant net of accumulated depreciation and amortization $ 2,402,903 $ 2,346,186 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining. (b) Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031. 2018 2017 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 13,580 35 $ 10,495 35 24 71 Gas transmission 423,873 48 366,433 48 22 66 Gas distribution 1,595,644 42 1,413,431 42 33 47 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciated (a) 46,369 N/A 47,466 N/A N/A N/A Storage 29,335 30 28,520 31 28 38 General 355,920 19 336,869 19 10 24 Total gas plant in service 2,468,260 2,206,753 Construction work in progress 38,271 44,440 Total gas plant 2,506,531 2,251,193 Less accumulated depreciation and amortization 279,580 229,170 Gas plant net of accumulated depreciation and amortization $ 2,226,951 $ 2,022,023 _____________ (a) Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides. 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 173,997 $ 11,796 $ 185,793 $ 64,273 $ 121,520 31 2 40 Mining $ 175,650 $ — $ 175,650 $ 111,689 $ 63,961 13 2 59 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 155,569 $ 224 $ 155,793 $ 57,813 $ 97,980 33 2 40 Mining $ 158,370 $ — $ 158,370 $ 108,844 $ 49,526 14 2 59 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 16,548 $ 22,269 $ 670 $ 17,945 $ 39,544 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $18 million . 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,580 $ 6,374 $ 11,954 $ 309 $ 14,070 $ 25,715 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million . |
Jointly Owned Facilities (Table
Jointly Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Jointly Owned Utility Plants | At December 31, 2018 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 115,198 $ 384 $ 61,730 Transmission Tie $ 20,855 $ 1,860 $ 6,667 Wygen I $ 119,273 $ 498 $ 44,155 Wygen III $ 140,072 $ 645 $ 22,647 |
Business Segment Information (T
Business Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting Information, Additional Information [Abstract] | |
Segment information included in Consolidated Balance Sheets | Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2018 2017 Electric (a) $ 2,895,577 $ 2,906,275 Gas 3,623,475 3,426,466 Power Generation (a) 154,203 60,852 Mining 80,594 65,455 Corporate and Other 209,478 115,612 Discontinued operations (b) — 84,242 Total assets $ 6,963,327 $ 6,658,902 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information. Capital Expenditures (a) for the years ended December 31, 2018 2017 Capital expenditures Electric Utilities $ 152,524 $ 138,060 Gas Utilities 288,438 184,389 Power Generation 30,945 1,864 Mining 18,794 6,708 Corporate and Other 11,723 6,668 Total capital expenditures of continuing operations 502,424 337,689 Total capital expenditures of discontinued operations 2,402 23,222 Total capital expenditures $ 504,826 $ 360,911 _________________ (a) Includes accruals for property, plant and equipment. Property, Plant and Equipment as of December 31, 2018 2017 Electric Utilities (a) $ 3,109,772 $ 2,990,208 Gas Utilities 2,506,531 2,251,193 Power Generation (a) 185,793 155,793 Mining 175,650 158,370 Corporate and Other 22,269 11,954 Total property, plant and equipment $ 6,000,015 $ 5,567,518 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. |
Segment information included in Consolidated Statements of Income | Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — — — 5,726 688,699 1,023,783 7,246 34,540 — — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 46,563 32,194 148 (103,181 ) — — Other revenues — — 35,143 1,299 379,775 (416,217 ) — — 22,752 1,524 81,706 33,493 379,923 (519,398 ) — — Total revenue 711,451 1,025,307 88,952 68,033 379,923 (519,398 ) — 1,754,268 Fuel, purchased power and cost of natural gas sold 277,093 462,153 — — 43 (113,679 ) — 625,610 Operations and maintenance 186,175 291,481 33,727 43,728 324,917 (344,735 ) — 535,293 Depreciation, depletion and amortization 98,639 86,434 6,913 7,965 21,161 (24,784 ) — 196,328 Operating income (loss) 149,544 185,239 48,312 16,340 33,802 (36,200 ) — 397,037 Interest expense (55,660 ) (85,760 ) (5,178 ) (538 ) (150,455 ) 155,975 — (141,616 ) Interest income 2,993 5,580 183 2 113,188 (120,305 ) — 1,641 Other income (expense), net (1,235 ) (431 ) (53 ) 164 456,481 (456,106 ) — (1,180 ) Income tax benefit (expense) (a) (16,702 ) 55,655 (8,267 ) (3,069 ) (3,804 ) (146 ) — 23,667 Income (loss) from continuing operations 78,940 160,283 34,997 12,899 449,212 (456,782 ) — 279,549 (Loss) from discontinued operations, net of tax — — — — — — (6,887 ) (6,887 ) Net income (loss) 78,940 160,283 34,997 12,899 449,212 (456,782 ) (6,887 ) 272,662 Net income attributable to noncontrolling interest — — (14,220 ) — — — — (14,220 ) Net income (loss) available for common stock $ 78,940 $ 160,283 $ 20,777 $ 12,899 $ 449,212 $ (456,782 ) $ (6,887 ) $ 258,442 ________________ (a) Income tax benefit (expense) includes a tax benefit of $73 million at our Gas Utilities resulting from legal entity restructuring. See Note 15 . Consolidating Income Statement Year ended December 31, 2017 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ — $ 1,680,266 Intercompany revenue 14,705 35 84,283 31,158 344,685 (474,866 ) — — Total revenue 704,650 947,630 91,546 66,621 344,685 (474,866 ) — 1,680,266 Fuel, purchased power and cost of natural gas sold 268,405 409,603 — — 151 (114,871 ) — 563,288 Operations and maintenance 172,307 269,190 32,382 44,882 296,067 (302,832 ) — 511,996 Depreciation, depletion and amortization 93,315 83,732 5,993 8,239 21,031 (24,064 ) — 188,246 Operating income (loss) 170,623 185,105 53,171 13,500 27,436 (33,099 ) — 416,736 Interest expense (55,229 ) (80,829 ) (3,959 ) (228 ) (152,416 ) 154,543 — (138,118 ) Interest income 2,955 2,254 1,123 23 115,382 (120,721 ) — 1,016 Other income (expense), net 1,730 (829 ) (54 ) 2,191 330,373 (331,303 ) — 2,108 Income tax benefit (expense) (9,997 ) (39,799 ) 10,333 (1,100 ) (32,433 ) (371 ) — (73,367 ) Income (loss) from continuing operations 110,082 65,902 60,614 14,386 288,342 (330,951 ) — 208,375 (Loss) from discontinued operations, net of tax (a) — — — — — — (17,099 ) (17,099 ) Net income (loss) 110,082 65,902 60,614 14,386 288,342 (330,951 ) (17,099 ) 191,276 Net income attributable to noncontrolling interest — (107 ) (14,135 ) — — — — (14,242 ) Net income (loss) available for common stock $ 110,082 $ 65,795 $ 46,479 $ 14,386 $ 288,342 $ (330,951 ) $ (17,099 ) $ 177,034 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ — $ — $ — $ 1,538,916 Intercompany revenue 12,951 — 83,955 31,213 347,500 (475,619 ) — — Total revenue 677,281 838,343 91,131 60,280 347,500 (475,619 ) — 1,538,916 Fuel, purchased power and cost of natural gas sold 261,349 352,165 — — 456 (114,838 ) — 499,132 Operations and maintenance 158,134 245,826 32,636 39,576 378,744 (326,846 ) — 528,070 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 22,930 (23,827 ) — 175,533 Operating income (loss) 173,153 162,017 54,391 11,358 (54,630 ) (10,108 ) — 336,181 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (114,597 ) 115,469 — (136,110 ) Interest income 5,946 1,573 1,983 24 97,147 (105,244 ) — 1,429 Other income (expense), net 3,193 184 2 2,209 179,838 (181,032 ) — 4,394 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 28,398 457 — (59,101 ) Income (loss) from continuing operations 85,827 59,726 35,489 10,053 136,156 (180,458 ) — 146,793 (Loss) from discontinued operations, net of tax (a) — — — — — — (64,162 ) (64,162 ) Net income (loss) 85,827 59,726 35,489 10,053 136,156 (180,458 ) (64,162 ) 82,631 Net income attributable to noncontrolling interest — (102 ) (9,559 ) — — — — (9,661 ) Net income (loss) available for common stock $ 85,827 $ 59,624 $ 25,930 $ 10,053 $ 136,156 $ (180,458 ) $ (64,162 ) $ 72,970 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . |
Disposal Groups, Including Discontinued Operations | The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 is as follows (in thousands): Year Ended Business Segment December 31, 2017 December 31, 2016 Electric Utilities $ 1,323 $ 2,079 Gas Utilities 1,571 2,292 Power Generation 177 320 Mining 101 196 Total reportable segments 3,172 4,887 Corporate and Other (a) 6,405 6,037 Total $ 9,577 $ 10,924 ________________________ (a) Includes interest allocations in 2017 and 2016 of approximately $4.9 million and $5.6 million , respectively. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2018 December 31, 2018 December 31, 2017 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% — 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% — 250,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes due 2033 May 1, 2033 4.35% 400,000 — Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Corporate term loan due 2019 August 9, 2019 2.55% — 300,000 Corporate term loan due 2020 (a) July 30, 2020 3.16% 300,000 — Corporate term loan due 2021 June 7, 2021 2.32% 12,921 18,664 Total Corporate debt 2,437,921 2,592,664 Less unamortized debt discount (5,122 ) (3,808 ) Total Corporate debt, net 2,432,799 2,588,856 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 1.73% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 1.73% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 1.93% 2,855 2,855 Total Electric Utilities debt 544,855 544,855 Less unamortized debt discount (86 ) (90 ) Total Electric Utilities debt, net 544,769 544,765 Total long-term debt 2,977,568 3,133,621 Less current maturities 5,743 5,743 Less unamortized deferred financing costs (d) 20,990 18,478 Long-term debt, net of current maturities and deferred financing costs $ 2,950,835 $ 3,109,400 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2018 and December 31, 2017 , respectively. |
Schedule of Maturities of Long-term Debt | Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2019 $ 5,743 2020 $ 505,743 2021 $ 8,435 2022 $ — 2023 $ 525,000 Thereafter $ 1,937,855 |
Deferred Financing Costs | Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2018 2018 2017 2016 $ 20,990 $ 2,829 $ 3,349 $ 3,861 |
Notes Payable (Tables)
Notes Payable (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Notes Payable [Abstract] | |
Schedule of Short-term Debt | We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): Balance Outstanding at December 31, 2018 December 31, 2017 CP Program $ 185,620 $ 211,300 |
Schedule of Credit Facility Covenants | Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: At December 31, 2018 Covenant Requirement at December 31, 2018 Consolidated Indebtedness to Capitalization Ratio 59 % Less than 65 % |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2017 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (b) December 31, 2018 Electric Utilities $ 6,287 $ — $ — $ 269 $ 2 $ 6,558 Gas Utilities 33,238 152 — 1,237 — 34,627 Mining 12,499 — (4 ) 649 2,471 15,615 Total $ 52,024 $ 152 $ (4 ) $ 2,155 $ 2,473 $ 56,800 December 31, 2016 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) December 31, 2017 Electric Utilities $ 4,661 $ — $ (4 ) $ 268 $ 1,362 $ 6,287 Gas Utilities 29,775 — — 1,142 2,321 33,238 Mining 12,440 — (107 ) 651 (485 ) 12,499 Total $ 46,876 $ — $ (111 ) $ 2,061 $ 3,198 $ 52,024 _____________________ (a) The Gas Utilities’ Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (b) The increase in the Mining Revision to Prior Estimates was primarily driven by higher costs associated with back-filling the pit with overburden removed during the mining process. |
Risk Management Activities (Tab
Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 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 by our Utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2018 December 31, 2017 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 4,000,000 24 8,330,000 36 Natural gas options purchased, net 4,320,000 13 3,540,000 14 Natural gas basis swaps purchased 3,960,000 24 8,060,000 36 Natural gas over-the-counter swaps, net (b) 3,660,000 24 3,820,000 29 Natural gas physical commitments, net (c) 18,325,852 30 12,826,605 35 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2018 , 1,542,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude contracts that qualify for normal purchase, normal sales exception. |
Derivative Instruments, Gain (Loss) | The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2018 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 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 $ (2,851 ) Interest expense $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (130 ) Fuel, purchased power and cost of natural gas sold — Total impact from cash flow hedges $ (2,981 ) $ — December 31, 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 $ (2,941 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 913 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Fuel, purchased power and cost of natural gas sold (75 ) Total $ (2,271 ) $ (75 ) December 31, 2016 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 $ (3,899 ) Interest expense $ (953 ) Commodity derivatives Net (loss) from discontinued operations 11,019 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) Fuel, purchased power and cost of natural gas sold — Total $ 7,106 $ (953 ) The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2018 , 2017 and 2016 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred. December 31, 2018 December 31, 2017 December 31, 2016 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ — $ — $ (31,222 ) Forward commodity contracts 983 366 (573 ) Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,851 2,941 3,899 Forward commodity contracts 130 (670 ) (11,005 ) Total other comprehensive income (loss) from hedging $ 3,964 $ 2,637 $ (38,901 ) Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2018 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 2018 December 31, 2017 December 31, 2016 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 Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ — $ (50 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold 1,101 (2,207 ) 940 $ 1,101 $ (2,207 ) $ 890 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Total $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Liabilities: Commodity derivatives - Utilities $ — $ 6,801 $ — $ (5,794 ) $ 1,007 Total $ — $ 6,801 $ — $ (5,794 ) $ 1,007 As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total 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 |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): December 31, Balance Sheet Location 2018 2017 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 415 $ — Noncurrent commodity derivatives Other assets, non-current 18 — Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (114 ) (817 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (4 ) (67 ) Total derivatives designated as hedges $ 315 $ (884 ) Not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,085 $ 304 Noncurrent commodity derivatives Other assets, non-current 1 — Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (833 ) (1,264 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (56 ) (111 ) Total derivatives not designated as hedges $ 197 $ (1,071 ) |
Schedule of Derivative Offsetting on Balance Sheet | Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2018 was as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,408 $ (1,408 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 1,519 — 1,519 Total derivative assets $ 2,927 $ (1,408 ) $ 1,519 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 5,794 $ (5,794 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 1,007 — 1,007 Total derivative liabilities $ 6,801 $ (5,794 ) $ 1,007 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2017 were as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,282 $ (1,282 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 304 — 304 Total derivative assets $ 1,586 $ (1,282 ) $ 304 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 11,497 $ (11,497 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 2,259 — 2,259 Total derivative liabilities $ 13,756 $ (11,497 ) $ 2,259 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 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 10 , were as follows at December 31 (in thousands): 2018 2017 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 20,776 $ 20,776 $ 15,420 $ 15,420 Restricted cash and equivalents (a) $ 3,369 $ 3,369 $ 2,820 $ 2,820 Notes payable (b) $ 185,620 $ 185,620 $ 211,300 $ 211,300 Long-term debt, including current maturities (c) (d) $ 2,956,578 $ 3,039,108 $ 3,115,143 $ 3,350,544 _______________ (a) Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings. 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. |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs | Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands): 2018 2017 2016 Stock-based compensation expense $ 12,390 $ 7,626 $ 10,885 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Variable Interest Entities | We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31: 2018 2017 (in thousands) Assets Current assets $ 13,620 $ 14,837 Property, plant and equipment of variable interest entities, net $ 199,839 $ 208,595 Liabilities Current liabilities $ 5,174 $ 4,565 |
Restricted Stock | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | A summary of the status of the restricted stock and restricted stock units at December 31, 2018 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 267 $ 55.94 Granted 113 57.31 Vested (119 ) 54.24 Forfeited (25 ) 55.52 Balance at end of period 236 $ 57.50 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2018 $ 57.31 $ 6,776 2017 $ 60.63 $ 7,909 2016 $ 53.55 $ 4,602 |
Performance Shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | Outstanding performance periods at December 31 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2016 January 1, 2016 - December 31, 2018 51 0% 200% January 1, 2017 January 1, 2017 - December 31, 2019 49 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 53 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2018 (in thousands) (in thousands) Performance Shares balance at beginning of period 74 $ 55.31 74 Granted 28 61.82 28 Forfeited (3 ) 58.14 (3 ) Vested (22 ) 54.92 (22 ) Performance Shares balance at end of period 77 $ 57.66 77 $ 76.03 _____________________ (a) The grant date fair values for the performance shares granted in 2018 , 2017 and 2016 were determined by Monte Carlo simulation using a blended volatility of 21% , 23% and 24% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2018 $ 61.82 December 31, 2017 $ 63.52 December 31, 2016 $ 47.76 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
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 $ 2.2 million June 2018 Kansas $ 1.9 million April 2018 Nebraska $ 3.8 million July 2018 South Dakota $ 7.6 million October 2018 |
Operating Leases (Tables)
Operating Leases (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Leases, Operating [Abstract] | |
Operating Leases of Lessor Disclosure | Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands): 2018 2017 2016 Rent expense (a) $ 2,667 $ 10,325 $ 9,568 _______________ (a) The decrease in rent expense is primarily driven by current year expiration of office leases and by purchases of facilities previously leased. |
Schedule of Future Minimum Rental Payments for Operating Leases | The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2019 $ 1,052 2020 $ 464 2021 $ 344 2022 $ 224 2023 $ 216 Thereafter $ 1,776 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2018 2017 2016 Current: Federal $ 325 $ (6,193 ) $ (21,806 ) State 247 (1,432 ) (1,797 ) 572 (7,625 ) (23,603 ) Deferred: Federal (23,295 ) 76,567 78,997 State 815 4,470 3,759 Excess deferred tax amortization (1,727 ) — — Tax credit amortization (32 ) (45 ) (52 ) (24,239 ) 80,992 82,704 $ (23,667 ) $ 73,367 $ 59,101 |
Schedule of Deferred Tax Assets and Liabilities | The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2018 2017 Deferred tax assets: Regulatory liabilities $ 92,966 $ 90,742 Employee benefits 14,039 18,724 Federal net operating loss 139,371 155,276 Other deferred tax assets (a) 101,579 74,561 Less: Valuation allowance (11,809 ) (9,121 ) Total deferred tax assets 336,146 330,182 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (529,338 ) (510,774 ) Regulatory assets (32,324 ) (26,245 ) Goodwill (b) (602 ) (46,392 ) State deferred tax liability (64,095 ) (58,930 ) Deferred costs (13,351 ) (16,063 ) Other deferred tax liabilities (7,767 ) (8,298 ) Total deferred tax liabilities (647,477 ) (666,702 ) Net deferred tax liability $ (311,331 ) $ (336,520 ) _______________ (a) Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) Legal entity restructuring - see above. |
Schedule of Effective Income Tax Rate Reconciliation | The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2018 2017 2016 Federal statutory rate 21.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 2.3 0.9 1.2 Percentage depletion (0.4 ) (0.6 ) (0.8 ) Non-controlling interest (a) (1.3 ) (1.8 ) (1.6 ) Equity AFUDC — (0.2 ) (0.5 ) Tax credits (2.0 ) (1.7 ) (0.4 ) Transaction costs — — 0.5 Accounting for uncertain tax positions adjustment — (0.2 ) (2.7 ) Flow-through adjustments (b) (1.6 ) (1.1 ) (2.1 ) Jurisdictional simplification project (d) (28.5 ) — — Other tax differences (0.4 ) (0.9 ) 0.1 IRC 172(f) carryback claim — (0.7 ) — TCJA corporate rate reduction (c) 1.6 (2.7 ) — (9.3 )% 26.0 % 28.7 % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (c) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded approximately $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded approximately $8.0 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (d) Legal entity restructuring - see above. |
Summary of Operating Loss Carryforwards | At December 31, 2018 , we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 663,741 2021 to 2038 State Net Operating Loss Carryforward $ 542,632 2019 to 2038 |
Summary of Income Tax Contingencies | The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2016 $ 31,986 Additions for prior year tax positions 2,423 Reductions for prior year tax positions (19,174 ) Additions for current year tax positions — Settlements (11,643 ) Ending balance at December 31, 2016 3,592 Additions for prior year tax positions 358 Reductions for prior year tax positions (5,713 ) Additions for current year tax positions 5,026 Settlements — Ending balance at December 31, 2017 3,263 Additions for prior year tax positions 251 Reductions for prior year tax positions (417 ) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 $ 3,583 |
State and Local Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Summary of State Tax Carryforwards | State tax credits have been generated and are available to offset future state income taxes. At December 31, 2018 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 20,285 2023 to 2036 Research and development $ 180 No expiration |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Statement of Comprehensive Income [Abstract] | |
Reclassification out of Accumulated Other Comprehensive Income | The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands): Location on the Consolidated Statements of Income (Loss) Amount Reclassified from AOCI December 31, 2018 December 31, 2017 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851 ) $ (2,941 ) Commodity contracts Net (loss) from discontinued operations — 913 Commodity contracts Fuel, purchased power and cost of natural gas sold (130 ) (243 ) (2,981 ) (2,271 ) Income tax Income tax benefit (expense) 630 875 Total reclassification adjustments related to cash flow hedges, net of tax $ (2,351 ) $ (1,396 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 178 $ 168 Prior service cost Net (loss) from discontinued operations — 29 Actuarial gain (loss) Operations and maintenance (2,487 ) (1,599 ) Actuarial gain (loss) Net (loss) from discontinued operations — (58 ) (2,309 ) (1,460 ) Income tax Income tax benefit (expense) 543 (516 ) Total reclassification adjustments related to defined benefit plans, net of tax (1,766 ) (1,976 ) Total reclassifications $ (4,117 ) $ (3,372 ) |
Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges 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 — 755 2,155 2,910 Amounts reclassified from AOCI 2,252 99 1,766 4,117 Reclassification to regulatory asset — — 6,519 6,519 Reclassification of certain tax effects from AOCI 22 (8 ) 726 740 As of December 31, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 231 (1,890 ) (1,659 ) Amounts reclassified from AOCI 1,912 (516 ) 944 2,340 Reclassification of certain tax effects from AOCI (3,384 ) — (3,616 ) (7,000 ) As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Years ended December 31, 2018 2017 2016 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 69,017 $ 28,191 $ 27,034 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 2,625 $ 3,198 $ 8,577 Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (137,965 ) $ (132,428 ) $ (113,627 ) Income taxes (paid) refunded $ (14,730 ) $ 1,775 $ (1,156 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2018 2017 Equity 17% 26% Real estate 4 4 Fixed income 71 63 Cash 3 1 Hedge funds 5 6 Total 100% 100% |
Schedule of Defined Contribution Plans Contributions | Contributions for the years ended December 31 were as follows (in thousands): 2018 2017 Defined Contribution Plan Company retirement contribution $ 8,766 $ 10,223 Matching contributions $ 13,559 $ 9,811 2018 2017 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 27,700 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 5,298 $ 4,332 Supplemental Non-Qualified Defined Benefit Plans $ 2,073 $ 3,217 |
Schedule of Changes in Projected Benefit Obligations | The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI: Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31 (in thousands), 2018 2017 2018 2017 2018 2017 Change in benefit obligation: Projected benefit obligation at beginning of year $ 474,725 $ 440,179 $ 45,112 $ 43,869 $ 69,339 $ 68,023 Service cost 6,834 7,034 1,764 2,937 2,291 2,300 Interest cost 15,470 15,520 1,170 1,276 2,085 2,141 Actuarial (gain) loss (31,340 ) 36,661 (2,963 ) 247 (9,045 ) (396 ) Amendments — — — — — 265 Benefits paid (20,308 ) (24,669 ) (2,073 ) (3,217 ) (5,298 ) (4,332 ) Plan participants’ contributions — — — — 1,445 1,338 Projected benefit obligation at end of year $ 445,381 $ 474,725 $ 43,010 $ 45,112 $ 60,817 $ 69,339 |
Schedule of Changes in Fair Value of Plan Assets | Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans (a) As of December 31 (in thousands), 2018 2017 2018 2017 2018 2017 Change in fair value of plan assets: Beginning fair value of plan assets $ 416,343 $ 364,695 $ — $ — $ 8,621 $ 8,470 Investment income (loss) (17,939 ) 48,617 — — (149 ) 120 Employer contributions 12,700 27,700 2,073 3,217 3,543 3,025 Retiree contributions — — — — 1,445 1,338 Benefits paid (20,308 ) (24,669 ) (2,073 ) (3,217 ) (5,298 ) (4,332 ) Ending fair value of plan assets $ 390,796 $ 416,343 $ — $ — $ 8,162 $ 8,621 ____________________ (a) Assets of VEBAs and Grantor Trust. |
Schedule of Amounts Recognized in Balance Sheet | The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2018 2017 2018 2017 Regulatory assets $ 82,919 $ 72,756 $ — $ — $ 6,655 $ 11,507 Current liabilities $ — $ — $ 1,463 $ 1,372 $ 3,885 $ 4,423 Non-current assets $ — $ — $ — $ — $ 249 $ 69 Non-current liabilities $ 54,585 $ 58,381 $ 41,547 $ 43,739 $ 49,015 $ 56,365 Regulatory liabilities $ 4,620 $ 5,232 $ — $ — $ 5,207 $ 3,334 |
Schedule of Accumulated and Projected Benefit Obligations | Accumulated Benefit Obligation Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31 (in thousands) 2018 2017 2018 2017 2018 2017 Accumulated Benefit Obligation $ 428,851 $ 450,394 $ 40,530 $ 41,243 $ 60,817 $ 69,339 |
Components of net periodic benefit cost | Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2016 2018 2017 2016 2018 2017 2016 Service cost $ 6,834 $ 7,034 $ 7,619 $ 1,764 $ 1,546 $ 1,335 $ 2,291 $ 2,300 $ 1,757 Interest cost 15,470 15,520 15,743 1,170 1,276 1,257 2,085 2,141 1,942 Expected return on assets (24,741 ) (24,517 ) (23,062 ) — — — (315 ) (315 ) (279 ) Net amortization of prior service cost 58 58 58 2 2 2 (398 ) (411 ) (428 ) Recognized net actuarial loss (gain) 8,632 4,007 7,173 1,000 1,001 829 216 499 335 Settlement expense (a) — — 10 — — — — — Net periodic expense $ 6,253 $ 2,102 $ 7,541 $ 3,936 $ 3,825 $ 3,423 $ 3,879 $ 4,214 $ 3,327 ____________________ (a) Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year. |
Schedule of Net Periodic Benefit Cost Not yet Recognized | For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2018 2017 2018 2017 2018 2017 Net (gain) loss $ 11,967 $ 10,056 $ 4,668 $ 6,639 $ 860 $ 1,309 Prior service cost (gain) 1 21 3 4 (317 ) (542 ) Reclassification of certain tax effects from AOCI (594 ) 2,087 (87 ) 1,371 (45 ) 158 Reclassification to regulatory asset (5,600 ) — — — (919 ) — Total AOCI $ 5,774 $ 12,164 $ 4,584 $ 8,014 $ (421 ) $ 925 |
Schedule of Assumptions Used | Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate 4.40 % 3.71 % 4.27 % 4.34 % 3.56 % 4.02 % 4.28 % 3.60 % 3.96 % Rate of increase in compensation levels 3.52 % 3.43 % 3.47 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate (a) 3.71 % 4.27 % 4.50 % 3.67 % 4.02 % 4.28 % 3.60 % 4.05 % 4.18 % Expected long-term rate of return on assets (b) 6.25 % 6.75 % 6.87 % N/A N/A N/A 3.93 % 3.88 % 3.83 % Rate of increase in compensation levels 3.43 % 3.47 % 3.42 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs. (b) The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost. |
Schedule of Health Care Cost Trend Rates | The healthcare benefit obligation was determined at December 31 as follows: 2018 2017 Trend Rate - Medical Pre-65 for next year - All Plans 6.70% 7.00% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.94% 5.00% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2026 2026 |
Schedule of Expected Benefit Payments | The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans 2019 $ 24,405 $ 1,463 $ 4,898 2020 $ 25,847 $ 1,406 $ 5,545 2021 $ 26,951 $ 1,617 $ 5,695 2022 $ 27,972 $ 1,727 $ 5,849 2023 $ 29,002 $ 1,912 $ 5,607 2024-2028 $ 151,915 $ 12,208 $ 24,953 |
Pension Plans, Defined Benefit | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,867 $ — $ 1,867 $ — $ 1,867 Common Collective Trust - Cash and Cash Equivalents — 9,923 — 9,923 — 9,923 Common Collective Trust - Equity — 67,457 — 67,457 — 67,457 Common Collective Trust - Fixed Income — 279,148 — 279,148 — 279,148 Common Collective Trust - Real Estate — 67 — 67 13,551 13,618 Hedge Funds — — — — 18,783 18,783 Total investments measured at fair value $ — $ 358,462 $ — $ 358,462 $ 32,334 $ 390,796 Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,280 $ — $ 1,280 $ — $ 1,280 Common Collective Trust - Cash and Cash Equivalents — 2,184 — 2,184 — 2,184 Common Collective Trust - Equity — 109,496 — 109,496 — 109,496 Common Collective Trust - Fixed Income — 262,329 — 262,329 — 262,329 Common Collective Trust - Real Estate — 1,728 — 1,728 15,701 17,429 Hedge Funds — — — — 23,625 23,625 Total investments measured at fair value $ — $ 377,017 $ — $ 377,017 $ 39,326 $ 416,343 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. |
Postretirement Health Coverage | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,873 $ — $ — $ 4,873 $ — $ 4,873 Equity Securities 1,005 — — 1,005 — 1,005 Intermediate-term Bond — 2,284 — 2,284 — 2,284 Total investments measured at fair value $ 5,878 $ 2,284 $ — $ 8,162 $ — $ 8,162 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,671 $ — $ — $ 4,671 $ — $ 4,671 Equity Securities 1,374 — — 1,374 — 1,374 Intermediate-term Bond — 2,576 — 2,576 — 2,576 Total investments measured at fair value $ 6,045 $ 2,576 $ — $ 8,621 $ — $ 8,621 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Long-term Purchase Commitment [Line Items] | |
Unrecorded Unconditional Purchase Obligations Disclosure | The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation and storage agreements 2019 $ 22,092 $ 129,018 2020 $ 6,837 $ 127,326 2021 $ 6,203 $ 118,707 2022 $ 6,203 $ 92,635 2023 $ 6,204 $ 73,919 Thereafter $ — $ 148,363 |
Power purchased | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2018 2017 2016 PPA with PacifiCorp $ 13,681 $ 13,218 $ 12,221 Transmission services agreement with PacifiCorp $ 1,742 $ 1,671 $ 1,428 PPA with Happy Jack $ 3,884 $ 3,846 $ 3,836 PPA with Silver Sage $ 5,376 $ 4,934 $ 4,949 Busch Ranch I Wind Farm (a) $ — $ 1,966 $ 2,071 PPA with Platte River Power Authority $ 223 $ — $ — PPAs with Cargill (b) $ — $ — $ 10,995 ________________ (a) On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I Wind Farm from AltaGas. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm. |
Purchased Gas Cost Obligation | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | At December 31, 2018 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): CIG Rockies NNG-Ventura NWPL-Wyoming Other 2019 5,803,117 3,650,000 720,000 236 2020 75,075 3,660,000 0 0 2021 0 3,650,000 0 0 2022 0 1,810,000 0 0 2023 0 0 0 0 Thereafter 0 0 0 0 |
Guarantees (Tables)
Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Guarantees [Abstract] | |
Schedule of Guarantor Obligations | We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2018 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 54,683 Ongoing Contract performance guarantee (b) 39,807 December 2019 $ 94,490 _______________________ (a) We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. (b) BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made. |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts | Total assets and liabilities of BHEP at December 31, 2017 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the final disposals occurring in 2018. As of (in thousands) December 31, 2017 Other current assets $ 10,360 Deferred income tax assets, noncurrent, net 16,966 Property, plant and equipment, net 56,916 Other current liabilities (18,966 ) Other noncurrent liabilities (22,808 ) Net assets $ 42,468 |
Disposal Groups, Including Discontinued Operations, Income Statement | Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands): For the Years Ended December 31, 2018 December 31, 2017 December 31, 2016 Revenue $ 5,897 $ 25,382 $ 34,058 Operations and maintenance 11,014 22,872 27,187 Loss on sale of assets 3,259 — — Depreciation, depletion and amortization 1,300 7,521 13,510 Impairment of long-lived assets — 20,385 106,957 Total operating expenses 15,573 50,778 147,654 Operating (loss) (9,676 ) (25,396 ) (113,596 ) Interest income (expense), net (19 ) 181 698 Other income (expense), net 190 (297 ) 110 Income tax benefit 2,618 8,413 48,626 (Loss) from discontinued operations $ (6,887 ) $ (17,099 ) $ (64,162 ) |
Oil and Gas Exploration and Pro
Oil and Gas Exploration and Production Industries Disclosure (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure | Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands): 2016 Acquisition of properties: Proved $ — Unproved 910 Exploration costs 1,102 Development costs 4,657 Asset retirement obligations incurred — Total costs incurred $ 6,669 |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding. 2016 Oil Gas NGL (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 3,450 73,412 1,752 Production (a) (319 ) (9,430 ) (133 ) Sales (570 ) (1,291 ) (17 ) Additions - extensions and discoveries 3 52 — Revisions to previous estimates (322 ) (8,173 ) 110 Balance at end of year 2,242 54,570 1,712 Proved developed reserves at end of year included above 2,242 54,570 1,712 Proved undeveloped reserves at the end of year included in above — — — NYMEX prices $ 42.75 $ 2.48 $ — Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 ________________________ (a) Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production. (c) For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54 /Mcf for Piceance, $0.92 /Mcf for San Juan and $0.53 /Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable. |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure | Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2016 Unproved oil and gas properties $ 18,547 Proved oil and gas properties 1,043,558 Gross capitalized costs 1,062,105 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) Net capitalized costs $ 62,014 |
Results of Operations for Oil and Gas Producing Activities Disclosure | Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2016 Revenue $ 34,058 Production costs 17,231 Depreciation, depletion and amortization 12,574 Impairment of long-lived assets 106,957 Total costs 136,762 Results of operations from producing activities before tax (102,704 ) Income tax benefit (expense) 37,916 Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) |
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands): 2016 Leasehold acquisition cost $ 963 Exploration cost 532 Capitalized interest 50 Total $ 1,545 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands): 2016 Future cash inflows $ 246,221 Future production costs (166,248 ) Future development costs, including plugging and abandonment (18,333 ) Future net cash flows 61,640 10% annual discount for estimated timing of cash flows (26,574 ) Standardized measure of discounted future net cash flows $ 35,066 |
Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures | The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands): 2016 Standardized measure - beginning of year $ 79,028 Sales and transfers of oil and gas produced, net of production costs (4,314 ) Net changes in prices and production costs (32,698 ) Changes in future development costs 1,825 Revisions of previous quantity estimates (7,477 ) Accretion of discount 7,903 Sales of reserves (9,201 ) Standardized measure - end of year $ 35,066 |
Quarterly Historical Data (Un_2
Quarterly Historical Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2018 and 2017 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2018 Revenue $ 575,389 $ 355,704 $ 321,979 $ 501,196 Operating income (loss) $ 148,274 $ 69,551 $ 65,085 $ 114,127 Income (loss) from continuing operations $ 138,977 $ 27,167 $ 21,801 $ 91,604 Income (loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income attributable to noncontrolling interest $ (3,630 ) $ (2,823 ) $ (3,994 ) $ (3,773 ) Net income (loss) available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Amounts attributable to common shareholders: Net income (loss) from continuing operations $ 135,347 $ 24,344 $ 17,807 $ 87,831 Net income (loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income (loss) available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Income (loss) per share for continuing operations - Basic $ 2.54 $ 0.46 $ 0.33 $ 1.52 Income (loss) per share for discontinued operations - Basic $ (0.05 ) $ (0.05 ) $ (0.02 ) $ (0.02 ) Earnings (loss) per share - Basic $ 2.49 $ 0.41 $ 0.32 $ 1.50 Income (loss) per share for continuing operations - Diluted $ 2.50 $ 0.45 $ 0.32 $ 1.51 Income (loss) per share for discontinued operations - Diluted $ (0.04 ) $ (0.05 ) $ (0.02 ) $ (0.02 ) Earnings (loss) per share - Diluted 2.46 0.40 0.31 1.49 Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million , respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2017 Revenue $ 547,528 $ 341,829 $ 335,611 $ 455,298 Operating income (loss) $ 150,186 $ 69,796 $ 79,559 $ 117,195 Income (loss) from continuing operations $ 81,715 $ 25,927 $ 32,898 $ 67,835 Income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income attributable to noncontrolling interest $ (3,623 ) $ (3,116 ) $ (3,935 ) $ (3,568 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Amounts attributable to common shareholders: Net income (loss) from continuing operations 78,092 22,811 28,963 64,267 Net income (loss) from discontinued operations (1,569 ) (616 ) (1,300 ) (13,614 ) Net income (loss) available for common stock 76,523 22,195 27,663 50,653 Income (loss) per share for continuing operations - Basic $ 1.47 $ 0.43 $ 0.54 $ 1.21 Income (loss) per share for discontinued operations - Basic (0.03 ) (0.01 ) (0.02 ) (0.26 ) Earnings (loss) per share - Basic $ 1.44 $ 0.42 $ 0.52 $ 0.95 Income (loss) per share for continuing operations - Diluted $ 1.42 $ 0.41 $ 0.52 $ 1.17 Income (loss) per share for discontinued operations - Diluted (0.03 ) (0.01 ) (0.02 ) (0.25 ) Earnings (loss) per share - Diluted $ 1.39 $ 0.40 $ 0.50 $ 0.92 Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13 million . |
Business Description And Sign_2
Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | $ (3,209) | $ (3,081) |
Accounts receivable, net | 269,153 | 248,330 |
Corporate, Non-Segment | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (169) | 0 |
Accounts receivable, net | 4,839 | 1,457 |
Electric Utilities | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (448) | (586) |
Accounts receivable, net | 74,398 | 75,145 |
Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (2,592) | (2,495) |
Accounts receivable, net | 184,052 | 167,728 |
Power Generation | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | 0 | 0 |
Accounts receivable, net | 1,876 | 1,196 |
Mining | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | 0 | 0 |
Accounts receivable, net | 3,988 | 2,804 |
Billed Revenues | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 146,716 | 126,060 |
Billed Revenues | Corporate, Non-Segment | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 5,008 | 1,457 |
Billed Revenues | Electric Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 39,721 | 39,347 |
Billed Revenues | Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 96,123 | 81,256 |
Billed Revenues | Power Generation | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 1,876 | 1,196 |
Billed Revenues | Mining | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 3,988 | 2,804 |
Unbilled Revenues | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 125,646 | 125,351 |
Unbilled Revenues | Corporate, Non-Segment | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 0 | 0 |
Unbilled Revenues | Electric Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 35,125 | 36,384 |
Unbilled Revenues | Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 90,521 | 88,967 |
Unbilled Revenues | Power Generation | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 0 | 0 |
Unbilled Revenues | Mining | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | $ 0 | $ 0 |
Business Description And Sign_3
Business Description And Significant Accounting Policies: Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Beginning of Year | $ 3,209 | $ 3,081 | $ 2,392 | $ 1,741 |
Adjustments | 0 | 0 | 2,158 | |
Additions Charged to Costs and Expenses | 6,859 | 4,926 | 2,704 | |
Recoveries and Other Additions | 4,092 | 8,262 | 4,915 | |
Write-offs and Other Deductions | (10,823) | (12,499) | (9,126) | |
Balance at End of Year | $ 3,209 | $ 3,081 | $ 2,392 |
Business Description And Sign_4
Business Description And Significant Accounting Policies: Revenue Recognition (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018USD ($)State | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)State | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 1,748,542 | ||||||||||
Revenue | $ 501,196 | $ 321,979 | $ 355,704 | $ 575,389 | $ 455,298 | $ 335,611 | $ 341,829 | $ 547,528 | $ 1,754,268 | $ 1,680,266 | $ 1,538,916 |
Significant Judgments and Estimates [Abstract] | |||||||||||
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 | $ 19,000 | ||||||||||
Regulatory liabilities | $ 540,794 | 485,126 | 540,794 | 485,126 | |||||||
Revenue Subject to Refund | |||||||||||
Significant Judgments and Estimates [Abstract] | |||||||||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 37,000 | ||||||||||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | 2,100 | ||||||||||
Regulatory liabilities | $ 18,032 | $ 0 | $ 18,032 | 0 | |||||||
Sale Agreement Between Colorado IPP and Affiliate Colorado Electric | |||||||||||
Revenue not in Scope of ASC 606 [Abstract] | |||||||||||
Long-term Purchase Commitment, Period | 20 years | ||||||||||
Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 33,609 | ||||||||||
Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,714,933 | ||||||||||
Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | 5,726 | ||||||||||
Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,461,317 | ||||||||||
Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 139,357 | ||||||||||
Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 39,521 | ||||||||||
Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 17,563 | ||||||||||
Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 90,784 | ||||||||||
Intercompany Eliminations | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (103,033) | ||||||||||
Revenue | (139,475) | $ (474,866) | $ (475,619) | ||||||||
Intercompany Eliminations | Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (32,194) | ||||||||||
Intercompany Eliminations | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (70,839) | ||||||||||
Intercompany Eliminations | Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | (36,442) | ||||||||||
Intercompany Eliminations | Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (32,194) | ||||||||||
Intercompany Eliminations | Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (1,348) | ||||||||||
Intercompany Eliminations | Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (46,562) | ||||||||||
Intercompany Eliminations | Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (8,102) | ||||||||||
Intercompany Eliminations | Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (14,827) | ||||||||||
Electric Utilities | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 709,024 | ||||||||||
Revenue | 711,451 | ||||||||||
Electric Utilities | Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Electric Utilities | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 709,024 | ||||||||||
Electric Utilities | Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | 2,427 | ||||||||||
Electric Utilities | Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 594,329 | ||||||||||
Electric Utilities | Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Electric Utilities | Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 33,687 | ||||||||||
Electric Utilities | Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 24,799 | ||||||||||
Electric Utilities | Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 56,209 | ||||||||||
Gas Utilities | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,024,352 | ||||||||||
Revenue | 1,025,307 | ||||||||||
Gas Utilities | Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Gas Utilities | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,024,352 | ||||||||||
Gas Utilities | Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | 955 | ||||||||||
Gas Utilities | Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 833,379 | ||||||||||
Gas Utilities | Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 140,705 | ||||||||||
Gas Utilities | Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Gas Utilities | Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 866 | ||||||||||
Gas Utilities | Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 49,402 | ||||||||||
Power Generation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52,396 | ||||||||||
Revenue | 88,952 | ||||||||||
Power Generation | Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Power Generation | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52,396 | ||||||||||
Power Generation | Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | 36,556 | ||||||||||
Power Generation | Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Power Generation | Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Power Generation | Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52,396 | ||||||||||
Power Generation | Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Power Generation | Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Mining | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 65,803 | ||||||||||
Revenue | 68,033 | ||||||||||
Mining | Services transferred at a point in time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 65,803 | ||||||||||
Mining | Services transferred over time | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Mining | Other revenues | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue | 2,230 | ||||||||||
Mining | Retail | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 65,803 | ||||||||||
Mining | Transportation | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Mining | Wholesale | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Mining | Market - off-system sales | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Mining | Transmission/Other | |||||||||||
Disaggregation of Revenue [Line Items] | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 0 |
Business Description And Sign_5
Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Materials and supplies | $ 75,081 | $ 69,732 |
Fuel - Electric Utilities | 2,850 | 2,962 |
Natural gas in storage | 39,368 | 40,589 |
Total materials, supplies and fuel | $ 117,299 | $ 113,283 |
Business Description And Sign_6
Business Description And Significant Accounting Policies: Investments (Details) - USD ($) $ in Thousands | Feb. 28, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
Investment [Line Items] | |||
Investments | $ 41,013 | $ 13,090 | |
Cost-method Investments | |||
Investment [Line Items] | |||
Assets Held for Sale Used to Acquire Other Investments | $ 28,000 | ||
Investments | 28,201 | 0 | |
Cash Surrender Value | |||
Investment [Line Items] | |||
Investments | $ 12,812 | $ 13,090 |
Business Description And Sign_7
Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accrued employee compensation, benefits and withholdings | $ 63,742 | $ 52,467 |
Accrued property taxes | 42,510 | 42,029 |
Customer Deposits and Prepayments | 43,574 | 44,420 |
Accrued interest | 31,759 | 33,822 |
Contributions in Aid of Construction | 1,485 | 1,552 |
Other (none of which is individually significant) | 32,431 | 45,172 |
Total accrued liabilities | $ 215,501 | $ 219,462 |
Business Description And Sign_8
Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | $ 1,299,454 | $ 1,299,454 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 1,299,454 | 1,299,454 |
Electric Utilities | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 248,479 | 248,479 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 248,479 | 248,479 |
Gas Utilities | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 1,042,210 | 1,042,210 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 1,042,210 | 1,042,210 |
Power Generation | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 8,765 | 8,765 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | $ 8,765 | $ 8,765 |
Business Description And Sign_9
Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 01, 2019 | |
Finite-Lived Intangible Assets [Roll Forward] | ||||
Intangible assets, net, beginning balance | $ 7,559 | $ 8,392 | $ 3,380 | |
Intangible assets, additions | 7,602 | 0 | 5,522 | |
Intangible assets, amortization expense | (824) | (833) | (510) | |
Intangible assets, net, ending balance | 14,337 | $ 7,559 | $ 8,392 | |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | ||||
Future Amortization Expense, Year One | 800 | |||
Future Amortization Expense, Year Two | 800 | |||
Future Amortization Expense, Year Three | 800 | |||
Future Amortization Expense, Year Four | 800 | |||
Future Amortization Expense, Year Five | $ 800 | |||
Minimum | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Finite-Lived Intangible Assets, Useful Life | 2 years | |||
Maximum | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Finite-Lived Intangible Assets, Useful Life | 40 years | |||
Subsequent Event | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Operating Lease, Right-of-Use Asset | $ 3,200 | |||
Operating Lease, Liability | $ 3,200 |
Business Description And Sig_10
Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) $ in Thousands | Apr. 29, 2016$ / Btu | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 284,235 | $ 297,454 | |
Regulatory Assets, Current | (48,776) | (81,016) | |
Regulatory assets, non-current | 235,459 | 216,438 | |
Regulatory liabilities | 540,794 | 485,126 | |
Regulatory Liability, Current | (29,810) | (6,832) | |
Regulatory liabilities, non-current | 510,984 | 478,294 | |
Deferred energy, fuel and gas cost adjustments - current | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 6,991 | 3,427 | |
Employee benefit plans | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 42,533 | 40,629 | |
Cost of removal | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 150,123 | 130,932 | |
Deferred Income Tax Charge | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 310,562 | 301,553 | |
Revenue Subject to Refund | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 18,032 | 0 | |
Other regulatory liabilities | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities | 12,553 | 8,585 | |
Deferred energy, fuel and gas cost adjustments - current | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 29,661 | 20,187 | |
Deferred gas cost adjustments | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 3,362 | 31,844 | |
Gas price derivatives | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 6,201 | 11,935 | |
Gas Price Derivatives [Abstract] | |||
Derivative, Remaining Maturity | 2 years | ||
Deferred taxes on AFUDC | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 7,841 | 7,847 | |
Employee benefit plans | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 110,524 | 109,235 | |
Environmental | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 959 | 1,031 | |
Asset retirement obligations | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 529 | 517 | |
Loss on reacquired debt | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 21,001 | 20,667 | |
Renewable energy standard adjustment | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 1,722 | 1,088 | |
Deferred taxes on flow through accounting | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 31,044 | 26,978 | |
Decommissioning costs | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 11,700 | 13,287 | |
Gas supply contract termination | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | 14,310 | 20,001 | |
Gas Supply Contract Termination [Abstract] | |||
Public Utilities, Approved Cost Recovery Period | 5 years | ||
Other regulatory assets | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 45,381 | $ 32,837 | |
Minimum | Gas supply contract termination | |||
Gas Supply Contract Termination [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 6 | ||
Maximum | Gas supply contract termination | |||
Gas Supply Contract Termination [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 8 |
Business Description And Sig_11
Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||
Net Income (Loss) Available to Common Stockholders, Basic | $ 86,571 | $ 16,950 | $ 21,917 | $ 133,004 | $ 50,653 | $ 27,663 | $ 22,195 | $ 76,523 | $ 258,442 | $ 177,034 | $ 72,970 |
Weighted average shares - Basic (in shares) | 54,420 | 53,221 | 51,922 | ||||||||
Dilutive effect of: | |||||||||||
Equity Units (in shares) | 898 | 1,783 | 1,222 | ||||||||
Equity compensation (in shares) | 168 | 116 | 127 | ||||||||
Weighted average shares - diluted (in shares) | 55,486 | 55,120 | 53,271 | ||||||||
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 1.49 | $ 0.31 | $ 0.40 | $ 2.46 | $ 0.92 | $ 0.50 | $ 0.40 | $ 1.39 | $ 4.66 | $ 3.21 | $ 1.37 |
Business Description And Sig_12
Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 16 | 11 | 3 |
Equity Compensation | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 16 | 11 | 3 |
Business Description And Sig_13
Business Description And Significant Accounting Policies: Leases (Details) - Subsequent Event $ in Millions | Jan. 01, 2019USD ($) |
Subsequent Event [Line Items] | |
Operating Lease, Right-of-Use Asset | $ 3.2 |
Operating Lease, Liability | $ 3.2 |
Business Description And Sig_14
Business Description And Significant Accounting Policies: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | Dec. 22, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Retained Earnings | Accounting Standards Update 2018-02 | |||
Reclassification of certain tax effects from AOCI | $ 7,000 | ||
Accumulated Other Comprehensive Income (Loss) | |||
Reclassification of certain tax effects from AOCI | $ 740 | $ (7,000) | |
Accumulated Other Comprehensive Income (Loss) | Accounting Standards Update 2018-02 | |||
Reclassification of certain tax effects from AOCI | $ (7,000) |
Business Description And Sig_15
Business Description And Significant Accounting Policies: Improvement To Employee Share-Based Payment Accounting (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Retained Earnings Adjustments [Line Items] | |
Tax effect of share-based compensation | $ 3,717 |
Retained Earnings | Accounting Standards Update 2016-09 | |
Retained Earnings Adjustments [Line Items] | |
Tax effect of share-based compensation | $ 3,184 |
Acquisition (Details)
Acquisition (Details) $ / shares in Units, $ in Thousands | Feb. 12, 2016USD ($) | Jan. 13, 2016USD ($) | Nov. 23, 2015USD ($)shares | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2018USD ($)customerutilitymishares | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)$ / sharesshares |
Acquisition Narrative [Abstract] | |||||||||||||||
Ownership of subsidiary (percent) | 100.00% | ||||||||||||||
Cash consideration paid | $ 1,135,000 | ||||||||||||||
Proceeds from issuance of shares | $ 536,000 | ||||||||||||||
Long-term debt - issuance | $ 546,000 | $ 700,000 | $ 0 | $ 1,767,608 | |||||||||||
Revenue - | $ 501,196 | $ 321,979 | $ 355,704 | $ 575,389 | $ 455,298 | $ 335,611 | $ 341,829 | $ 547,528 | 1,754,268 | 1,680,266 | 1,538,916 | ||||
Net income (loss) available for common stock | 86,571 | $ 16,950 | $ 21,917 | $ 133,004 | 50,653 | $ 27,663 | $ 22,195 | 76,523 | 258,442 | 177,034 | 72,970 | ||||
Cash consideration paid | 0 | 0 | 1,124,238 | ||||||||||||
Goodwill | 1,299,454 | 1,299,454 | $ 1,299,454 | 1,299,454 | 1,299,454 | 1,299,454 | |||||||||
Acquisition Recap [Abstract] | |||||||||||||||
Consideration paid, net of working capital adjustment received | 0 | 0 | (1,124,238) | ||||||||||||
Goodwill | 1,299,454 | $ 1,299,454 | 1,299,454 | $ 1,299,454 | 1,299,454 | 1,299,454 | |||||||||
Pro Forma Results | |||||||||||||||
Estimated combined federal and state income tax rate (percent) | 37.00% | ||||||||||||||
Noncontrolling Interest [Abstract] | |||||||||||||||
Payments for Repurchase of Redeemable Noncontrolling Interest | $ 5,600 | ||||||||||||||
Corporate, Non-Segment | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Pre-tax, incremental acquisition costs | 45,000 | ||||||||||||||
Revenue - | $ 379,923 | $ 344,685 | $ 347,500 | ||||||||||||
Remarketable Junior Subordinated Notes Due 2028 | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Issuance of equity units | shares | 5,980,000 | ||||||||||||||
Common Stock | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Issuance of common stock, shares | shares | 6,325,000 | 6,371,690 | 1,968,738 | ||||||||||||
Source Gas | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Purchase Price | 1,894,882 | ||||||||||||||
Assumed long-term debt | 760,000 | ||||||||||||||
Number of natural gas utilities acquired | utility | 4 | ||||||||||||||
Number of customers served with acquisition | customer | 429,000 | ||||||||||||||
Length of natural gas pipeline (miles) | mi | 512 | ||||||||||||||
Revenue - | $ 348,000 | ||||||||||||||
Net income (loss) available for common stock | $ 15,000 | ||||||||||||||
Cash consideration paid | (1,124,238) | ||||||||||||||
Goodwill | 939,695 | ||||||||||||||
Less: Working capital adjustment received | (10,644) | ||||||||||||||
Expected tax deductible goodwill | $ 252,000 | $ 252,000 | |||||||||||||
Acquisition Recap [Abstract] | |||||||||||||||
Purchase Price | 1,894,882 | ||||||||||||||
Less: Long-term debt assumed | (760,000) | ||||||||||||||
Less: Working capital adjustment received | (10,644) | ||||||||||||||
Consideration paid, net of working capital adjustment received | 1,124,238 | ||||||||||||||
Current Assets | 112,983 | ||||||||||||||
Property, plant & equipment, net | 1,058,093 | ||||||||||||||
Goodwill | 939,695 | ||||||||||||||
Deferred charges and other assets, excluding goodwill | 133,299 | ||||||||||||||
Current liabilities | (172,454) | ||||||||||||||
Long-term debt | (758,874) | ||||||||||||||
Deferred credits and other liabilities | (188,504) | ||||||||||||||
Total consideration paid, net of working-capital adjustment received | $ 1,124,238 | ||||||||||||||
Pro Forma Results | |||||||||||||||
Revenue | 1,617,878 | ||||||||||||||
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax | 177,040 | ||||||||||||||
Net income (loss) | $ 112,878 | ||||||||||||||
Earnings (loss) per share, Basic (usd per share) | $ / shares | $ 3.41 | ||||||||||||||
Earnings (loss) per share, Diluted (usd per share) | $ / shares | $ 3.32 | ||||||||||||||
Former SourceGas Noncontrolling Interest | |||||||||||||||
Noncontrolling Interest [Abstract] | |||||||||||||||
Sellers retention (percent) | 0.50% |
Property, Plant and Equipment_2
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 6,000,015 | $ 5,567,518 |
Less: accumulated depreciation, depletion and amortization | 1,145,136 | 1,026,088 |
Total property, plant and equipment, net | 4,854,879 | 4,541,430 |
Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 22,269 | 11,954 |
Less: accumulated depreciation, depletion and amortization | 670 | 309 |
Total property, plant and equipment, net | 39,544 | 25,715 |
Property, plant and equipment | 5,721 | 5,580 |
Construction in progress, gross | 16,548 | 6,374 |
Intercompany Eliminations | ||
Property, Plant and Equipment [Line Items] | ||
Accumulated Depreciation - Capital Lease Elimination | $ 17,945 | $ 14,070 |
Weighted Average | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 8 years | 8 years |
Minimum | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 3 years | 3 years |
Maximum | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 30 years | 30 years |
Electric Utilities | ||
Property, Plant and Equipment [Line Items] | ||
Total plant in service before construction work in progress | $ 3,049,292 | $ 2,976,613 |
Construction work in progress | 60,480 | 13,595 |
Property, plant and equipment, gross | 3,109,772 | 2,990,208 |
Less: accumulated depreciation, depletion and amortization | 706,869 | 644,022 |
Total property, plant and equipment, net | $ 2,402,903 | 2,346,186 |
Depreciation, depletion and amortization, remaining amortization period | 12 years | |
Electric Utilities | Production, Electric | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 1,318,643 | $ 1,315,044 |
Electric Utilities | Production, Electric | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 41 years | 39 years |
Electric Utilities | Production, Electric | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | Production, Electric | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 46 years | |
Electric Utilities | Electric transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 437,082 | $ 407,203 |
Electric Utilities | Electric transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 51 years | 51 years |
Electric Utilities | Electric transmission | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | |
Electric Utilities | Electric transmission | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 53 years | |
Electric Utilities | Electric distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 793,725 | $ 755,213 |
Electric Utilities | Electric distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | 48 years |
Electric Utilities | Electric distribution | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 45 years | |
Electric Utilities | Electric distribution | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 50 years | |
Electric Utilities | Plant acquisition adjustment | ||
Property, Plant and Equipment [Line Items] | ||
Plant acquisition adjustment | $ 4,870 | $ 4,870 |
Electric Utilities | Plant acquisition adjustment | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | 32 years |
Electric Utilities | Plant acquisition adjustment | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | Plant acquisition adjustment | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 32 years | |
Electric Utilities | General | ||
Property, Plant and Equipment [Line Items] | ||
General | $ 233,531 | $ 232,842 |
Electric Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | 31 years |
Electric Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 26 years | |
Electric Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Electric Utilities | Capital lease - plant in service | ||
Property, Plant and Equipment [Line Items] | ||
Capital lease - plant in service | $ 261,441 | $ 261,441 |
Electric Utilities | Capital lease - plant in service | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 20 years | 20 years |
Electric Utilities | Capital lease - plant in service | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 20 years | |
Electric Utilities | Capital lease - plant in service | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 20 years | |
Gas Utilities | ||
Property, Plant and Equipment [Line Items] | ||
Total plant in service before construction work in progress | $ 2,468,260 | $ 2,206,753 |
Construction work in progress | 38,271 | 44,440 |
Property, plant and equipment, gross | 2,506,531 | 2,251,193 |
Less: accumulated depreciation, depletion and amortization | 279,580 | 229,170 |
Total property, plant and equipment, net | 2,226,951 | 2,022,023 |
Gas Utilities | Production, Gas | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 13,580 | $ 10,495 |
Gas Utilities | Production, Gas | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 35 years | 35 years |
Gas Utilities | Production, Gas | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 24 years | |
Gas Utilities | Production, Gas | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 71 years | |
Gas Utilities | Gas transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 423,873 | $ 366,433 |
Gas Utilities | Gas transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | 48 years |
Gas Utilities | Gas transmission | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 22 years | |
Gas Utilities | Gas transmission | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 66 years | |
Gas Utilities | Gas distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 1,595,644 | $ 1,413,431 |
Gas Utilities | Gas distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 42 years | 42 years |
Gas Utilities | Gas distribution | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 33 years | |
Gas Utilities | Gas distribution | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 47 years | |
Gas Utilities | Cushion Gas - Depreciable | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 3,539 | $ 3,539 |
Gas Utilities | Cushion Gas - Depreciable | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | 28 years |
Gas Utilities | Cushion Gas - Depreciable | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Gas Utilities | Cushion Gas - Depreciable | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Gas Utilities | Cushion Gas - Not Depreciated | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 46,369 | $ 47,466 |
Gas Utilities | Gas, Storage | ||
Property, Plant and Equipment [Line Items] | ||
Production, processing and storage | $ 29,335 | $ 28,520 |
Gas Utilities | Gas, Storage | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 30 years | 31 years |
Gas Utilities | Gas, Storage | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | |
Gas Utilities | Gas, Storage | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 38 years | |
Gas Utilities | General | ||
Property, Plant and Equipment [Line Items] | ||
General | $ 355,920 | $ 336,869 |
Gas Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 19 years | 19 years |
Gas Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 10 years | |
Gas Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 24 years | |
Power Generation | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 185,793 | $ 155,793 |
Less: accumulated depreciation, depletion and amortization | 64,273 | 57,813 |
Total property, plant and equipment, net | 121,520 | 97,980 |
Property, plant and equipment | 173,997 | 155,569 |
Construction in progress, gross | $ 11,796 | $ 224 |
Power Generation | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 31 years | 33 years |
Power Generation | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 2 years | 2 years |
Power Generation | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 40 years | 40 years |
Mining | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 175,650 | $ 158,370 |
Less: accumulated depreciation, depletion and amortization | 111,689 | 108,844 |
Total property, plant and equipment, net | 63,961 | 49,526 |
Property, plant and equipment | 175,650 | 158,370 |
Construction in progress, gross | $ 0 | $ 0 |
Mining | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 13 years | 14 years |
Mining | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 2 years | 2 years |
Mining | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 59 years | 59 years |
Jointly Owned Facilities (Detai
Jointly Owned Facilities (Details) $ in Thousands | Dec. 11, 2018MW | Dec. 31, 2018USD ($)MW |
Wyodak Plant | Electric Utilities | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership Share Percentage | 20.00% | |
Plant in Service | $ 115,198 | |
Construction Work in Progress | 384 | |
Accumulated Depreciation | $ 61,730 | |
Transmission Tie | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 400 | |
Transmission Tie | West to East Transmission Tie | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 200 | |
Transmission Tie | East to West Transmission Tie | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 200 | |
Transmission Tie | Electric Utilities | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership Share Percentage | 35.00% | |
Plant in Service | $ 20,855 | |
Construction Work in Progress | 1,860 | |
Accumulated Depreciation | $ 6,667 | |
Wygen I Generating Facility | Power Generation | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership Share Percentage | 76.50% | |
Plant in Service | $ 119,273 | |
Construction Work in Progress | 498 | |
Accumulated Depreciation | $ 44,155 | |
Wygen I I I Generating Facility | Electric Utilities | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership Share Percentage | 52.00% | |
Plant in Service | $ 140,072 | |
Construction Work in Progress | 645 | |
Accumulated Depreciation | $ 22,647 | |
Busch Ranch I Wind Farm | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 29 | |
Busch Ranch I Wind Farm | Electric Utilities | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Ownership Share Percentage | 50.00% |
Jointly Owned Facilities_ Joint
Jointly Owned Facilities: Jointly Owned Facility - Related Party (Details) $ in Millions | Dec. 11, 2018USD ($)MW | Dec. 31, 2018 |
AltaGas | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
Total consideration paid, net of working-capital adjustment received | $ 16 | |
Busch Ranch I Wind Farm | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Utility Plant, Megawatt Capacity | MW | 29 | |
Busch Ranch I Wind Farm | AltaGas | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
Electric Utilities | Busch Ranch I Wind Farm | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | |
Fair Value | AltaGas | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Property, plant & equipment, net | $ 8.7 | |
Fair Value | Contractual Rights | AltaGas | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Indefinite-lived Intangible Assets Acquired | $ 7.6 |
Business Segment Information_ S
Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 6,963,327 | $ 6,658,902 |
Discontinued Operations, Held-for-sale | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 0 | 84,242 |
Corporate, Non-Segment | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 209,478 | 115,612 |
Electric Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 2,895,577 | 2,906,275 |
Gas Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 3,623,475 | 3,426,466 |
Power Generation | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 154,203 | 60,852 |
Mining | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 80,594 | $ 65,455 |
Business Segment Information_ C
Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | $ 502,424 | $ 337,689 |
Capital Expenditure, Discontinued Operations | 2,402 | 23,222 |
Property, Plant and Equipment Including New Asset Acquisitions, Gross Period Increase (Decrease) | 504,826 | 360,911 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | 11,723 | 6,668 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | 152,524 | 138,060 |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | 288,438 | 184,389 |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | 30,945 | 1,864 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Capital Expenditures and Asset Acquisitions | $ 18,794 | $ 6,708 |
Business Segment Information_ P
Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 6,000,015 | $ 5,567,518 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 22,269 | 11,954 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 3,109,772 | 2,990,208 |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 2,506,531 | 2,251,193 |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 185,793 | 155,793 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 175,650 | $ 158,370 |
Business Segment Information_ I
Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 1,748,542 | ||||||||||
Revenue | $ 501,196 | $ 321,979 | $ 355,704 | $ 575,389 | $ 455,298 | $ 335,611 | $ 341,829 | $ 547,528 | 1,754,268 | $ 1,680,266 | $ 1,538,916 |
Fuel, purchased power and cost of natural gas sold | 625,610 | 563,288 | 499,132 | ||||||||
Operations and maintenance | 535,293 | 511,996 | 528,070 | ||||||||
Depreciation, depletion and amortization | 196,328 | 188,246 | 175,533 | ||||||||
Operating income | 114,127 | 65,085 | 69,551 | 148,274 | 117,195 | 79,559 | 69,796 | 150,186 | 397,037 | 416,736 | 336,181 |
Interest expense | (141,616) | (138,118) | (136,110) | ||||||||
Interest income | 1,641 | 1,016 | 1,429 | ||||||||
Other income (expense), net | (1,180) | 2,108 | 4,394 | ||||||||
Income tax benefit (expense) | 23,667 | (73,367) | (59,101) | ||||||||
Income from continuing operations | 91,604 | 21,801 | 27,167 | 138,977 | 67,835 | 32,898 | 25,927 | 81,715 | 279,549 | 208,375 | 146,793 |
(Income) loss from discontinued operations, net of tax | (1,260) | (857) | (2,427) | (2,343) | (13,614) | (1,300) | (616) | (1,569) | (6,887) | (17,099) | (64,162) |
Net income (loss) | 272,662 | 191,276 | 82,631 | ||||||||
Net income attributable to noncontrolling interest | (3,773) | $ (3,994) | $ (2,823) | (3,630) | $ (3,568) | $ (3,935) | $ (3,116) | $ (3,623) | (14,220) | (14,242) | (9,661) |
Net income (loss) available for common stock | 258,442 | 177,034 | 72,970 | ||||||||
Deferred Income Tax Expense (Benefit) | 24,239 | (80,992) | (82,704) | ||||||||
Other Restructuring | |||||||||||
Segment Reporting Information | |||||||||||
Deferred Income Tax Expense (Benefit) | $ (23,000) | $ (49,000) | (73,000) | ||||||||
Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 709,024 | ||||||||||
Revenue | 711,451 | ||||||||||
Fuel, purchased power and cost of natural gas sold | 277,093 | 268,405 | 261,349 | ||||||||
Operations and maintenance | 186,175 | 172,307 | 158,134 | ||||||||
Depreciation, depletion and amortization | 98,639 | 93,315 | 84,645 | ||||||||
Operating income | 149,544 | 170,623 | 173,153 | ||||||||
Interest expense | (55,660) | (55,229) | (56,237) | ||||||||
Interest income | 2,993 | 2,955 | 5,946 | ||||||||
Other income (expense), net | (1,235) | 1,730 | 3,193 | ||||||||
Income tax benefit (expense) | (16,702) | (9,997) | (40,228) | ||||||||
Income from continuing operations | 78,940 | 110,082 | 85,827 | ||||||||
Net income (loss) | 78,940 | 110,082 | 85,827 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 78,940 | 110,082 | 85,827 | ||||||||
Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,024,352 | ||||||||||
Revenue | 1,025,307 | ||||||||||
Fuel, purchased power and cost of natural gas sold | 462,153 | 409,603 | 352,165 | ||||||||
Operations and maintenance | 291,481 | 269,190 | 245,826 | ||||||||
Depreciation, depletion and amortization | 86,434 | 83,732 | 78,335 | ||||||||
Operating income | 185,239 | 185,105 | 162,017 | ||||||||
Interest expense | (85,760) | (80,829) | (76,586) | ||||||||
Interest income | 5,580 | 2,254 | 1,573 | ||||||||
Other income (expense), net | (431) | (829) | 184 | ||||||||
Income tax benefit (expense) | 55,655 | (39,799) | (27,462) | ||||||||
Income from continuing operations | 160,283 | 65,902 | 59,726 | ||||||||
Net income (loss) | 160,283 | 65,902 | 59,726 | ||||||||
Net income attributable to noncontrolling interest | 0 | (107) | (102) | ||||||||
Net income (loss) available for common stock | 160,283 | 65,795 | 59,624 | ||||||||
Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52,396 | ||||||||||
Revenue | 88,952 | ||||||||||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||||||||
Operations and maintenance | 33,727 | 32,382 | 32,636 | ||||||||
Depreciation, depletion and amortization | 6,913 | 5,993 | 4,104 | ||||||||
Operating income | 48,312 | 53,171 | 54,391 | ||||||||
Interest expense | (5,178) | (3,959) | (3,758) | ||||||||
Interest income | 183 | 1,123 | 1,983 | ||||||||
Other income (expense), net | (53) | (54) | 2 | ||||||||
Income tax benefit (expense) | (8,267) | 10,333 | (17,129) | ||||||||
Income from continuing operations | 34,997 | 60,614 | 35,489 | ||||||||
Net income (loss) | 34,997 | 60,614 | 35,489 | ||||||||
Net income attributable to noncontrolling interest | (14,220) | (14,135) | (9,559) | ||||||||
Net income (loss) available for common stock | 20,777 | 46,479 | 25,930 | ||||||||
Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 65,803 | ||||||||||
Revenue | 68,033 | ||||||||||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||||||||
Operations and maintenance | 43,728 | 44,882 | 39,576 | ||||||||
Depreciation, depletion and amortization | 7,965 | 8,239 | 9,346 | ||||||||
Operating income | 16,340 | 13,500 | 11,358 | ||||||||
Interest expense | (538) | (228) | (401) | ||||||||
Interest income | 2 | 23 | 24 | ||||||||
Other income (expense), net | 164 | 2,191 | 2,209 | ||||||||
Income tax benefit (expense) | (3,069) | (1,100) | (3,137) | ||||||||
Income from continuing operations | 12,899 | 14,386 | 10,053 | ||||||||
Net income (loss) | 12,899 | 14,386 | 10,053 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 12,899 | 14,386 | 10,053 | ||||||||
Intercompany Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (103,033) | ||||||||||
Revenue | (139,475) | (474,866) | (475,619) | ||||||||
Fuel, purchased power and cost of natural gas sold | (113,679) | (114,871) | (114,838) | ||||||||
Operations and maintenance | (344,735) | (302,832) | (326,846) | ||||||||
Depreciation, depletion and amortization | (24,784) | (24,064) | (23,827) | ||||||||
Operating income | (36,200) | (33,099) | (10,108) | ||||||||
Interest expense | 155,975 | 154,543 | 115,469 | ||||||||
Interest income | (120,305) | (120,721) | (105,244) | ||||||||
Other income (expense), net | (456,106) | (331,303) | (181,032) | ||||||||
Income tax benefit (expense) | (146) | (371) | 457 | ||||||||
Income from continuing operations | (456,782) | (330,951) | (180,458) | ||||||||
Net income (loss) | (456,782) | (330,951) | (180,458) | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | (456,782) | (330,951) | (180,458) | ||||||||
Operating Segments | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 704,650 | 677,281 | |||||||||
Operating Segments | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 947,630 | 838,343 | |||||||||
Operating Segments | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 91,546 | 91,131 | |||||||||
Operating Segments | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 66,621 | 60,280 | |||||||||
Corporate, Non-Segment | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 379,923 | 344,685 | 347,500 | ||||||||
Fuel, purchased power and cost of natural gas sold | 43 | 151 | 456 | ||||||||
Operations and maintenance | 324,917 | 296,067 | 378,744 | ||||||||
Depreciation, depletion and amortization | 21,161 | 21,031 | 22,930 | ||||||||
Operating income | 33,802 | 27,436 | (54,630) | ||||||||
Interest expense | (150,455) | (152,416) | (114,597) | ||||||||
Interest income | 113,188 | 115,382 | 97,147 | ||||||||
Other income (expense), net | 456,481 | 330,373 | 179,838 | ||||||||
Income tax benefit (expense) | (3,804) | (32,433) | 28,398 | ||||||||
Income from continuing operations | 449,212 | 288,342 | 136,156 | ||||||||
Net income (loss) | 449,212 | 288,342 | 136,156 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 449,212 | 288,342 | 136,156 | ||||||||
Consolidation, Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | 0 | |||||||||
External Customers | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,748,542 | ||||||||||
Revenue | 1,754,268 | ||||||||||
External Customers | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 686,272 | ||||||||||
Revenue | 688,699 | 689,945 | 664,330 | ||||||||
External Customers | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,022,828 | ||||||||||
Revenue | 1,023,783 | 947,595 | 838,343 | ||||||||
External Customers | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 5,833 | ||||||||||
Revenue | 7,246 | 7,263 | 7,176 | ||||||||
External Customers | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 33,609 | ||||||||||
Revenue | 34,540 | 35,463 | 29,067 | ||||||||
Intercompany Customers | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | ||||||||||
Revenue | 0 | ||||||||||
Intercompany Customers | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 22,752 | ||||||||||
Revenue | 22,752 | 14,705 | 12,951 | ||||||||
Intercompany Customers | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,524 | ||||||||||
Revenue | 1,524 | 35 | 0 | ||||||||
Intercompany Customers | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 46,563 | ||||||||||
Revenue | 81,706 | 84,283 | 83,955 | ||||||||
Intercompany Customers | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 32,194 | ||||||||||
Revenue | 33,493 | $ 31,158 | $ 31,213 | ||||||||
Intercompany Customers | Intercompany Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (103,181) | ||||||||||
Revenue | (519,398) | ||||||||||
Intercompany Customers | Corporate, Non-Segment | |||||||||||
Segment Reporting Information | |||||||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 148 | ||||||||||
Revenue | 379,923 | ||||||||||
Other revenues | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 5,726 | ||||||||||
Other revenues | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 2,427 | ||||||||||
Other revenues | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 955 | ||||||||||
Other revenues | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 36,556 | ||||||||||
Other revenues | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 2,230 | ||||||||||
Other revenues | Intercompany Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | (36,442) | ||||||||||
Other revenues | External Customers | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 5,726 | ||||||||||
Other revenues | External Customers | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 2,427 | ||||||||||
Other revenues | External Customers | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 955 | ||||||||||
Other revenues | External Customers | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 1,413 | ||||||||||
Other revenues | External Customers | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 931 | ||||||||||
Other revenues | Intercompany Customers | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | ||||||||||
Other revenues | Intercompany Customers | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | ||||||||||
Other revenues | Intercompany Customers | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | ||||||||||
Other revenues | Intercompany Customers | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 35,143 | ||||||||||
Other revenues | Intercompany Customers | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 1,299 | ||||||||||
Other revenues | Intercompany Customers | Intercompany Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | (416,217) | ||||||||||
Other revenues | Intercompany Customers | Corporate, Non-Segment | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | $ 379,775 |
Business Segment Information__2
Business Segment Information: Corporate Expense Reallocation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | $ 9,577 | $ 10,924 |
Segment Reconciling Items | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 3,172 | 4,887 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 6,405 | 6,037 |
Corporate, Non-Segment | Interest Expense | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 4,900 | 5,600 |
Expenses Allocated to Corporate, Non-Segment | Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 1,323 | 2,079 |
Expenses Allocated to Corporate, Non-Segment | Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 1,571 | 2,292 |
Expenses Allocated to Corporate, Non-Segment | Power Generation | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | 177 | 320 |
Expenses Allocated to Corporate, Non-Segment | Mining | ||
Segment Reporting Information [Line Items] | ||
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated | $ 101 | $ 196 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 12, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | |||
Total long-term debt | $ 2,977,568 | $ 3,133,621 | |
Less current maturities | (5,743) | (5,743) | |
Less unamortized deferred financing costs | (20,990) | (18,478) | |
Long-term debt, net of current maturities | 2,950,835 | 3,109,400 | |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Less unamortized deferred financing costs | (2,300) | (1,700) | |
Senior Unsecured Notes Due 2019 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 2.50% | ||
Corporate Term Loan Due July 2020 | |||
Debt Instrument [Line Items] | |||
Long-term debt | 300,000 | ||
Electric Utilities | |||
Debt Instrument [Line Items] | |||
Long-term debt | 544,855 | 544,855 | |
Less unamortized debt discount | (86) | (90) | |
Total long-term debt | $ 544,769 | 544,765 | |
Electric Utilities | First Mortgage Bonds Due 2032 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 7.23% | ||
Long-term debt | $ 75,000 | 75,000 | |
Electric Utilities | First Mortgage Bonds Due 2039 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 6.125% | ||
Long-term debt | $ 180,000 | 180,000 | |
Electric Utilities | First Mortgage Bonds Due 2037 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 6.67% | ||
Long-term debt | $ 110,000 | 110,000 | |
Electric Utilities | Industrial Development Revenue Bonds Due 2021 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 1.73% | ||
Long-term debt | $ 7,000 | 7,000 | |
Electric Utilities | Industrial Development Revenue Bonds Due 2027 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 1.73% | ||
Long-term debt | $ 10,000 | 10,000 | |
Electric Utilities | Series 94 A Debt, Due 2024 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 1.93% | ||
Long-term debt | $ 2,855 | 2,855 | |
Black Hills Corporation | Corporate, Non-Segment | |||
Debt Instrument [Line Items] | |||
Long-term debt | 2,437,921 | 2,592,664 | |
Less unamortized debt discount | (5,122) | (3,808) | |
Total long-term debt | $ 2,432,799 | 2,588,856 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2023 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 4.25% | ||
Long-term debt | $ 525,000 | 525,000 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2020 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 5.875% | ||
Long-term debt | $ 200,000 | 200,000 | |
Black Hills Corporation | Corporate, Non-Segment | Remarketable Junior Subordinated Notes Due 2028 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 3.50% | ||
Long-term debt | $ 0 | 299,000 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 2.50% | ||
Long-term debt | $ 0 | 250,000 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 3.95% | ||
Long-term debt | $ 300,000 | 300,000 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 3.15% | ||
Long-term debt | $ 400,000 | 400,000 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2033 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 4.35% | ||
Long-term debt | $ 400,000 | 0 | |
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 4.20% | ||
Long-term debt | $ 300,000 | 300,000 | |
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due August 2019 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 2.55% | ||
Long-term debt | $ 0 | 300,000 | |
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 2.32% | ||
Long-term debt | $ 12,921 | 18,664 | |
Black Hills Corporation | Corporate, Non-Segment | London Interbank Offered Rate (LIBOR) | Corporate Term Loan Due July 2020 | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 3.16% | ||
Long-term debt | $ 300,000 | 0 | |
South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2044 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 4.43% | ||
Long-term debt | $ 85,000 | 85,000 | |
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2044 | |||
Debt Instrument [Line Items] | |||
Interest rate (percent) | 4.53% | ||
Long-term debt | $ 75,000 | $ 75,000 |
Long-Term Debt_ Aggregate Matur
Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Long-term Debt, Unclassified [Abstract] | ||
2,019 | $ 5,743 | $ 5,743 |
2,020 | 505,743 | |
2,021 | 8,435 | |
2,022 | 0 | |
2,023 | 525,000 | |
Thereafter | $ 1,937,855 |
Long-Term Debt_ Debt Transactio
Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands | Dec. 12, 2018 | Aug. 17, 2018 | Jul. 17, 2017 | May 16, 2017 | Dec. 31, 2018 | Dec. 31, 2017 |
Remarketable Junior Subordinated Notes Due 2028 | ||||||
Debt Instrument [Line Items] | ||||||
Extinguishment of Debt, Amount | $ 299,000 | |||||
Corporate Term Loan Due July 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 300,000 | |||||
Senior Unsecured Notes Due 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Extinguishment of Debt, Amount | $ 250,000 | |||||
Interest rate (percent) | 2.50% | |||||
Corporate, Non-Segment | Corporate Term Loan Due 2033 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 4.35% | |||||
Proceeds from senior unsecured notes | $ 400,000 | |||||
Black Hills Corporation | Corporate Term Loan Due August 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Extinguishment of Debt, Amount | $ 50,000 | $ 50,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 2,437,921 | $ 2,592,664 | ||||
Black Hills Corporation | Corporate, Non-Segment | Remarketable Junior Subordinated Notes Due 2028 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.50% | |||||
Long-term debt | $ 0 | 299,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.15% | |||||
Long-term debt | $ 400,000 | 400,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 4.20% | |||||
Long-term debt | $ 300,000 | 300,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due August 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 2.55% | |||||
Long-term debt | $ 0 | 300,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 2.32% | |||||
Long-term debt | $ 12,921 | 18,664 | ||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.95% | |||||
Long-term debt | $ 300,000 | 300,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 2.50% | |||||
Long-term debt | $ 0 | $ 250,000 | ||||
Junior Subordinated Debt | Remarketable Junior Subordinated Notes Due 2028 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 4.579% | |||||
Base Rate | Corporate Term Loan Due July 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.00% | |||||
Eurodollar | Corporate Term Loan Due July 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 0.70% |
Long-Term Debt_ Amortization Ex
Long-Term Debt: Amortization Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Long-term Debt, Unclassified [Abstract] | |||
Deferred Finance Costs Remaining, Noncurrent | $ 20,990 | ||
Amortization expense for deferred financing costs | $ 2,829 | $ 3,349 | $ 3,861 |
Long-Term Debt_ Dividend Restri
Long-Term Debt: Dividend Restrictions (Details) $ in Millions | Dec. 31, 2018USD ($) |
Utilities Group | |
Debt Instrument [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 257 |
Notes Payable (Details)
Notes Payable (Details) | 12 Months Ended | |||
Dec. 31, 2018USD ($)credit_extension | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jul. 30, 2018USD ($) | |
Short-term Debt [Line Items] | ||||
Notes payable | $ 185,620,000 | $ 211,300,000 | ||
Commercial Paper, Maximum Borrowing Capacity | 750,000,000 | |||
Net increase (decrease) in commercial paper and short-term borrowings | $ (25,680,000) | 114,700,000 | $ 19,800,000 | |
Maximum | ||||
Debt Covenants [Abstract] | ||||
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year | 0.65 | |||
Commercial Paper | ||||
Short-term Debt [Line Items] | ||||
Notes payable | $ 185,620,000 | 211,300,000 | ||
Debt Instrument, Term | 397 days | |||
Debt, Weighted Average Interest Rate | 2.88% | |||
Revolving Credit Facility | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Current Borrowing Capacity | $ 750,000,000 | |||
Number Of One-Year Extension Options | credit_extension | 2 | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,000,000,000 | |||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.175% | |||
Debt Instrument, Term | 1 year | |||
Letters of Credit Outstanding, Amount | $ 22,000,000 | $ 27,000,000 | ||
Debt Issuance Cost, Gross, Noncurrent | $ 6,700,000 | |||
Debt Covenants [Abstract] | ||||
Recourse Leverage Ratio | 59.00% | |||
Debt Instrument, Consolidated Indebtedness to Capitalization Ratio | 0.65 | |||
Revolving Credit Facility | Base Rate | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 0.125% | |||
Revolving Credit Facility | Eurodollar | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 1.125% | |||
Revolving Credit Facility | Letter of Credit | ||||
Short-term Debt [Line Items] | ||||
Line of Credit Facility, Interest Rate at Period End | 1.125% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | $ 52,024 | $ 46,876 |
Liabilities Incurred | 152 | 0 |
Liabilities Settled | (4) | (111) |
Accretion | 2,155 | 2,061 |
Revisions to Prior Estimates | 2,473 | 3,198 |
Ending Balance | 56,800 | 52,024 |
Electric Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 6,287 | 4,661 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | 0 | (4) |
Accretion | 269 | 268 |
Revisions to Prior Estimates | 2 | 1,362 |
Ending Balance | 6,558 | 6,287 |
Gas Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 33,238 | 29,775 |
Liabilities Incurred | 152 | 0 |
Liabilities Settled | 0 | 0 |
Accretion | 1,237 | 1,142 |
Revisions to Prior Estimates | 0 | 2,321 |
Ending Balance | 34,627 | 33,238 |
Mining | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 12,499 | 12,440 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | (4) | (107) |
Accretion | 649 | 651 |
Revisions to Prior Estimates | 2,471 | (485) |
Ending Balance | $ 15,615 | $ 12,499 |
Risk Management Activities_ Uti
Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions | 12 Months Ended | |
Dec. 31, 2018USD ($)MMBTU | Dec. 31, 2017MMBTU | |
Future | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 4,000,000 | 8,330,000 |
Derivative, Remaining Maturity | 24 months | 36 months |
Commodity Option | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 4,320,000 | 3,540,000 |
Derivative, Remaining Maturity | 13 months | 14 months |
Basis Swap | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 3,960,000 | 8,060,000 |
Derivative, Remaining Maturity | 24 months | 36 months |
Fixed for Float Swaps Purchased | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 3,660,000 | 3,820,000 |
Derivative, Remaining Maturity | 24 months | 29 months |
Fixed for Float Swaps Purchased | Cash Flow Hedging | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | 1,542,000 | |
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $ | $ 0.4 | |
Natural Gas Physical Purchases | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 18,325,852 | 12,826,605 |
Derivative, Remaining Maturity | 30 months | 35 months |
Risk Management Activities_ Cas
Risk Management Activities: Cash Flow Hedges (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ 0 | $ (75) | $ (953) |
Cash Flow Hedging | Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | 3,964 | 2,637 | (38,901) |
Interest Rate Swap | Cash Flow Hedging | Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2,851 | 2,941 | 3,899 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax | 0 | 0 | (31,222) |
Interest Rate Swap | Interest Expense | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | (953) |
Commodity Contract | Cash Flow Hedging | Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 130 | (670) | (11,005) |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax | 983 | 366 | (573) |
Commodity Contract | Net (loss) from Discontinued Operations | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | |
Commodity Contract | Fuel, purchased power and cost of natural gas sold | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | (75) | 0 |
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Cash Flow Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2,981) | (2,271) | 7,106 |
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Interest Rate Swap | Interest Expense | Cash Flow Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2,851) | (2,941) | (3,899) |
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Commodity Contract | Net (loss) from Discontinued Operations | Cash Flow Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 913 | 11,019 | |
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Commodity Contract | Fuel, purchased power and cost of natural gas sold | Cash Flow Hedging | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | $ (130) | $ (243) | $ (14) |
Risk Management Activities_ Der
Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | $ 284,235 | $ 297,454 | |
Deferred Derivative Gain (Loss) | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | 6,200 | 12,000 | |
Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 1,101 | (2,207) | $ 890 |
Net (loss) from Discontinued Operations | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | (50) |
Fuel, purchased power and cost of natural gas sold | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 1,101 | $ (2,207) | $ 940 |
Schedule of Fair Values (Detail
Schedule of Fair Values (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | $ 1,519 | $ 304 |
Derivative, Liabilities, Fair Value Disclosure | 1,007 | 2,259 |
Fair Value, Measurements, Recurring | ||
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 | (1,408) | (1,282) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (5,794) | (11,497) |
Fair Value, Measurements, Recurring | Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 1,519 | 304 |
Derivative Liabilities, Total | 1,007 | 2,259 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 2,927 | 1,586 |
Derivative Liabilities, Total | 6,801 | 13,756 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 0 | 0 |
Derivative Liabilities, Total | 0 | 0 |
Fair Value, Measurements, Recurring | Commodity Contract | ||
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 | (1,408) | (1,282) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (5,794) | (11,497) |
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 1,519 | 304 |
Derivative, Liabilities, Fair Value Disclosure | 1,007 | 2,259 |
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value, Inputs, Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 2,927 | 1,586 |
Derivative, Liabilities, Fair Value Disclosure | 6,801 | 13,756 |
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value, Inputs, Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | $ 0 | $ 0 |
Fair Value Measurements_ Balanc
Fair Value Measurements: Balance Sheet Location (Details) - Commodity derivatives - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Designated as Hedging Instrument | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedges, Net | $ 315 | $ (884) |
Designated as Hedging Instrument | Derivative Assets, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedge Assets | 415 | 0 |
Designated as Hedging Instrument | Derivative Assets, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedge Assets | 18 | 0 |
Designated as Hedging Instrument | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Current | (114) | (817) |
Designated as Hedging Instrument | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Current | (4) | (67) |
Not Designated as Hedging Instrument | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedges, Net | 197 | (1,071) |
Not Designated as Hedging Instrument | Derivative Assets, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedge Assets | 1,085 | 304 |
Not Designated as Hedging Instrument | Derivative Assets, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Fair Value Hedge Assets | 1 | 0 |
Not Designated as Hedging Instrument | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Current | (833) | (1,264) |
Not Designated as Hedging Instrument | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Current | $ (56) | $ (111) |
Fair Value Measurements_ Bala_2
Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | $ 2,927 | $ 1,586 |
Gross Amounts Offset In Statement Of Financial Position Assets | (1,408) | (1,282) |
Derivative Asset | 1,519 | 304 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 6,801 | 13,756 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (5,794) | (11,497) |
Derivative Liability | 1,007 | 2,259 |
Contract Subject to Master Netting Arrangement | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 1,408 | 1,282 |
Gross Amounts Offset In Statement Of Financial Position Assets | (1,408) | (1,282) |
Derivative Asset | 0 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 5,794 | 11,497 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (5,794) | (11,497) |
Derivative Liability | 0 | 0 |
Contract Not Subject to Master Netting Arrangement | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 1,519 | 304 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 1,519 | 304 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1,007 | 2,259 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | 0 |
Derivative Liability | $ 1,007 | $ 2,259 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | $ 20,776 | $ 15,420 |
Restricted cash - carrying amount | 3,369 | 2,820 |
Notes payable | 185,620 | 211,300 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | 20,776 | 15,420 |
Restricted cash - carrying amount | 3,369 | 2,820 |
Notes payable | 185,620 | 211,300 |
Long-term debt, including current maturities - carrying amount | 2,956,578 | 3,115,143 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and Cash Equivalents, Fair Value Disclosure | 20,776 | 15,420 |
Restricted Cash Fair Value Disclosure | 3,369 | 2,820 |
Notes payable - fair value | 185,620 | 211,300 |
Long-term debt, including current maturities - fair value | $ 3,039,108 | $ 3,350,544 |
Equity Units (Details)
Equity Units (Details) $ / shares in Units, shares in Thousands | Dec. 12, 2018USD ($) | Nov. 01, 2018USD ($)shares | Oct. 29, 2018$ / shares | Aug. 17, 2018USD ($) | Nov. 23, 2015USD ($)shares$ / shares |
Debt Instrument [Line Items] | |||||
Proceeds from Sale of Interest in Corporate Unit | $ 299,000,000 | ||||
Equity Unit Stated Amount (usd per share) | $ / shares | $ 50 | $ 50 | |||
Corporate Units Ownership Interest Percentage In Subordinated Notes | 5.00% | ||||
Debt Instrument, Subordinated Notes, Stated Principal Amount | $ 1,000 | ||||
Debt Instrument, Convertible, Threshold Consecutive Trading Days | 20 days | ||||
Sale of Stock, Consideration Received on Transaction | $ 299,000,000 | ||||
Sale of Stock, Number of Shares Issued in Transaction | shares | 6,372 | ||||
Remarketable Junior Subordinated Notes Due 2028 | |||||
Debt Instrument [Line Items] | |||||
Issuance of equity units | shares | 5,980 | ||||
Debt Instrument, Convertible, Conversion Ratio | 1.0655 | ||||
Extinguishment of Debt, Amount | $ 299,000,000 | ||||
Senior Unsecured Notes Due 2019 | |||||
Debt Instrument [Line Items] | |||||
Extinguishment of Debt, Amount | $ 250,000,000 |
Equity_ At-the-Market Equity Of
Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Aug. 04, 2017 | Jun. 30, 2016 | |
At The Market Equity Offering Program Authorized Aggregate Value | $ 300 | $ 200 | |
Common Stock | |||
At The Market Equity Offering Program Shares Issued | 1,968,738 | ||
At The Market Equity Program Proceeds from Sale of Stock | $ 119 | ||
Payments of Stock Issuance Costs | $ 1.2 |
Equity_ Equity Compensation Pla
Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |||
Shares available for grant | 800,180 | ||
Unrecognized compensation expense | $ 12,000 | ||
Weighted-average recognition period | 1 year 11 months | ||
Stock-based compensation expense | $ 12,390 | $ 7,626 | $ 10,885 |
Equity_ Stock Options (Details)
Equity: Stock Options (Details) | Dec. 31, 2018shares |
Employee Stock Option | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares exercisable at end of period | 68,749 |
Equity_ Restricted Stock (Detai
Equity: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value | |||
Unrecognized compensation expense | $ 12,000 | ||
Weighted-average recognition period | 1 year 11 months | ||
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award vesting period | 3 years | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested Number of Shares [Roll Forward] | |||
Restricted Stock balance at beginning of period | 267 | ||
Shares Granted | 113 | ||
Shares Vested | (119) | ||
Shares Forfeited | (25) | ||
Restricted Stock at end of period | 236 | 267 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value | |||
Balance at beginning of period (usd per share) | $ 55.94 | ||
Granted (usd per share) | 57.31 | $ 60.63 | $ 53.55 |
Vested (usd per share) | 54.24 | ||
Forfeited (usd per share) | 55.52 | ||
Balance at end of period (usd per share) | $ 57.50 | $ 55.94 | |
Restricted Stock and RSUs, total fair value of shares vested | $ 6,776 | $ 7,909 | $ 4,602 |
Unrecognized compensation expense | $ 8,900 | ||
Weighted-average recognition period | 2 years 1 month |
Equity_ Performance Share Plan
Equity: Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation expense | $ 12 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Performance Goal - Percentile of Peer Group Performance | 74.80% | ||
Weighted-average recognition period | 1 year 11 months | ||
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award Payout, Cash Percentage | 50.00% | ||
Performance Share Award Payout, Shares of Common Stock Percentage | 50.00% | ||
The percentage paid in cash for the accrued equity portion of the performance share plan upon change in control | 100.00% | ||
Unrecognized compensation expense | $ 2.8 | ||
Performance Share Award, Percentage of Target | 161.90% | ||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 49 | 51 | |
Performance Shares, Number of Shares Authorized, End of Period | 53 | 49 | 51 |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Granted (usd per share) | $ 61.82 | ||
Blended volatility | 21.00% | 23.00% | 24.00% |
Historical volatility | 50.00% | ||
Weighted Average Grant Date Fair Value (usd per share) | $ 63.52 | $ 47.76 | |
Target shares, value | $ 5.7 | ||
Unrecognized compensation expense | $ 3.2 | ||
Weighted-average recognition period | 1 year 9 months | ||
Performance Shares, Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 74 | ||
Performance Shares, Granted in Period | 28 | ||
Performance Shares, Forfeited in Period | (3) | ||
Performance Shares, Vested in Period | (22) | ||
Performance Shares, Number of Shares Authorized, End of Period | 77 | 74 | |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Balance at end of period (usd per share) | $ 76.03 | ||
Performance Shares, Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 74 | ||
Performance Shares, Granted in Period | 28 | ||
Performance Shares, Forfeited in Period | (3) | ||
Performance Shares, Vested in Period | (22) | ||
Performance Shares, Number of Shares Authorized, End of Period | 77 | 74 | |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Balance at beginning of period (usd per share) | $ 55.31 | ||
Forfeited (usd per share) | 58.14 | ||
Vested (usd per share) | 54.92 | ||
Balance at end of period (usd per share) | $ 57.66 | $ 55.31 | |
Minimum | Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award, Percentage of Target | 0.00% | 0.00% | 0.00% |
Maximum | Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance Share Award, Percentage of Target | 200.00% | 200.00% | 200.00% |
Equity_ Dividend Reinvestment a
Equity: Dividend Reinvestment and Stock Purchase Plan (Details) | Dec. 31, 2018shares |
Class of Stock [Line Items] | |
Unissued Shares Available | 253,418 |
Dividend Reinvestment Plan | |
Class of Stock [Line Items] | |
Percent of recent average market price | 100.00% |
Equity_ Preferred Stock (Detail
Equity: Preferred Stock (Details) | Dec. 31, 2018shares |
Stockholders' Equity Note [Abstract] | |
Preferred Stock, Shares Authorized | 25,000,000 |
Preferred Stock, Shares Outstanding | 0 |
Equity_ Noncontrolling Interest
Equity: Noncontrolling Interest in Subsidiary (Details) $ in Thousands | Apr. 14, 2016USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)MW | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Electric Generation Capacity, Megawatts | MW | 200 | |||||||||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||||||||||
Proceeds from Noncontrolling Interests | $ 216,000 | $ 0 | $ 0 | $ 216,370 | ||||||||
Number of Days the Company has to Pay Distributions of Net Income Attributable to Noncontrolling Interests | 30 days | |||||||||||
Net income attributable to noncontrolling interest | $ (3,773) | $ (3,994) | $ (2,823) | $ (3,630) | $ (3,568) | $ (3,935) | $ (3,116) | $ (3,623) | $ (14,220) | (14,242) | (9,661) | |
Power Generation | ||||||||||||
Net income attributable to noncontrolling interest | (14,220) | (14,135) | $ (9,559) | |||||||||
Current assets | ||||||||||||
Assets | 13,620 | 14,837 | 13,620 | 14,837 | ||||||||
Property, plant and equipment of variable interest entities, net | ||||||||||||
Assets | 199,839 | 208,595 | 199,839 | 208,595 | ||||||||
Current liabilities | ||||||||||||
Liabilities | $ 5,174 | $ 4,565 | $ 5,174 | $ 4,565 |
Regulatory Matters_ TCJA Revenu
Regulatory Matters: TCJA Revenue Reserve (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018USD ($)State | Dec. 31, 2017utility | |
Number of States That Have Received State Utility Commission Approvals to Provide the Benefits of Federal Tax Reform to Utility Customers | State | 6 | |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 19 | |
Public Utilities, Number of Rate Review Requests Filed | utility | 3 | |
Arkansas Public Service Commission (APSC) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 9.7 | |
Colorado Public Utilities Commission (CPUC) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 10.8 | |
Iowa Utilities Board (IUB) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 2.2 | |
Kansas Public Utilities Commission (KPUC) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 1.9 | |
Nebraska Public Service Commission (NPSC) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 3.8 | |
South Dakota Public Utilities Commission (SDPUC) | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 7.6 | |
Revenue Subject to Refund | ||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | 37 | |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 2.1 |
Regulatory Matters_ Excess Defe
Regulatory Matters: Excess Deferred Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 309 | |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 19 | |
Deferred Income Tax Charge | ||
Tax Cuts and Jobs Act of 2017, Provisional Income Tax Expense (Benefit) | 311 | |
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 301 | |
Revenue Subject to Refund | ||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 2.1 |
Regulatory Matters_ Electric Ut
Regulatory Matters: Electric Utilities Regulatory Activity (Details) | Dec. 17, 2018USD ($)MW | Oct. 31, 2018USD ($) | Jan. 01, 2018USD ($) | Jul. 01, 2017USD ($) | Jun. 16, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2018USD ($) |
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory liabilities | $ 485,126,000 | $ 540,794,000 | |||||
Regulatory assets | 297,454,000 | 284,235,000 | |||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Public Utilities, Aggregate Amount of Customer Credits Through The Power Cost Adjustment Mechanism | $ 7,000,000 | ||||||
Public Utilities, Power Purchase Agreement Annual Cost Escalation Percentage Through 2022 | 3.00% | ||||||
Federal Energy Regulatory Commission (FERC) Common Use System (CUS) | South Dakota Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Annual Revenue Requirement, as Required by the FERC Joint-Access Transmission Tariff | $ 1,900,000 | ||||||
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff | $ 31,000,000 | ||||||
South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Public Utilities, Suspension Of Rate Increase Due to a Moratorium by State Regulators | $ 1,000,000 | ||||||
Public Utilities, Increase in Amortization Expense Due to Change in Amortization Periods | $ 2,700,000 | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 0 | ||||||
Environmental Restoration Costs | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | 13,287,000 | 11,700,000 | |||||
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Public Utilities, Moratorium Period | 6 years | ||||||
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | 13,000,000 | ||||||
Other regulatory assets | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | 32,837,000 | 45,381,000 | |||||
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Public Utilities, Moratorium Period | 6 years | ||||||
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | 14,000,000 | ||||||
Corriedale Wind Project | Wyoming Public Service Commission (WPSC) | South Dakota Electric and Wyoming Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment | $ 57,000,000 | ||||||
Utility Plant, Megawatt Capacity | MW | 40 | ||||||
Other regulatory liabilities | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory liabilities | $ 8,585,000 | 12,553,000 | |||||
Other regulatory liabilities | Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Electric | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory liabilities | $ 6,000,000 | ||||||
Previously Reported | Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory Asset, Amortization Period | 10 years | ||||||
Previously Reported | Other regulatory assets | South Dakota Public Utilities Commission (SDPUC) | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory Asset, Amortization Period | 10 years |
Regulatory Matters_ Gas Utiliti
Regulatory Matters: Gas Utilities Regulatory Activity (Details) | Feb. 01, 2019USD ($)utility | Jan. 01, 2019USD ($) | Nov. 20, 2018USD ($)customermi | Oct. 05, 2018USD ($) | Sep. 05, 2018USD ($) | Jul. 16, 2018USD ($) | Jun. 19, 2018USD ($) | Jun. 01, 2018USD ($) | Feb. 01, 2018USD ($) | Oct. 10, 2018USD ($)utility |
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 1,100,000 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.90% | |||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 46.63% | |||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 53.37% | |||||||||
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Number of Customers Served | customer | 57,000 | |||||||||
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment | $ 54,000,000 | |||||||||
Length Of Natural Gas Pipeline Replace, Upgrade and Maintain | mi | 35 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 1,000,000 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.60% | |||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 54.00% | |||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 46.00% | |||||||||
Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 12,000,000 | |||||||||
Public Utilities, Amount Of Existing Revenue Collected Through Rider Mechanisms Included In New Base Rates | $ 11,000,000 | |||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.61% | |||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 49.10% | |||||||||
Public Utilities, Approved Debt Capital Structure, Percentage | 50.90% | |||||||||
Kansas Corporation Commission | Black Hills Energy, Kansas Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 600,000 | |||||||||
Eligible Capital Investments Under the Gas System Rider | $ 8,000,000 | |||||||||
Nebraska Public Service Commission (NPSC) | Black Hills Gas Distribution - Nebraska | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 6,000,000 | |||||||||
Nebraska Public Service Commission (NPSC) | Black Hills Energy, Nebraska Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment | $ 6,800,000 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 300,000 | |||||||||
Subsequent Event | Kansas Corporation Commission | Black Hills Energy, Kansas Gas | Minimum | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Eligible Capital Investments Under the Gas System Rider | $ 8,000,000 | |||||||||
Subsequent Event | Kansas Corporation Commission | Black Hills Energy, Kansas Gas | Maximum | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Eligible Capital Investments Under the Gas System Rider | $ 16,000,000 | |||||||||
Received Approval to Request Consolidation | Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Colorado Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Number of Companies Being Merged | utility | 2 | |||||||||
Public Utilities, Number of Customers Served | 187,000 | |||||||||
Rate Review Filed with the Regulatory Agency | Subsequent Event | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Number of Companies Being Merged | utility | 2 | |||||||||
Rate Review Filed with the Regulatory Agency | Subsequent Event | Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Colorado Gas | ||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 2,500,000 |
Operating Leases (Details)
Operating Leases (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating Leases, Rent Expense, Net [Abstract] | |||
Rent expense | $ 2,667 | $ 10,325 | $ 9,568 |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2,019 | 1,052 | ||
2,020 | 464 | ||
2,021 | 344 | ||
2,022 | 224 | ||
2,023 | 216 | ||
Thereafter | $ 1,776 |
Income Taxes_ Tax Cut and Jobs
Income Taxes: Tax Cut and Jobs Act (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 309,000 | ||
Increase (Decrease) in Regulatory Liabilities | $ 18,533 | (4,536) | $ (14,082) |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | 19,000 | ||
Deferred Income Tax Charge | |||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 301,000 | ||
Increase (Decrease) in Regulatory Liabilities | 11,000 | ||
Revenue Subject to Refund | |||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 2,100 |
Income Taxes_ Tax Benefit Relat
Income Taxes: Tax Benefit Related to Legal Restructuring (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 | ||
Other Restructuring | |||||
Deferred Tax Assets, Goodwill and Intangible Assets | $ 73,000 | 73,000 | |||
Deferred Income Tax Expense (Benefit) | $ 23,000 | $ 49,000 | $ 73,000 |
Income Taxes_ Current and Defer
Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Current: | |||
Federal | $ 325 | $ (6,193) | $ (21,806) |
State | 247 | (1,432) | (1,797) |
Total Current | 572 | (7,625) | (23,603) |
Deferred: | |||
Federal | (23,295) | 76,567 | 78,997 |
State | 815 | 4,470 | 3,759 |
Excess Deferred Amortization | (1,727) | 0 | 0 |
Tax credit amortization | (32) | (45) | (52) |
Total Deferred | (24,239) | 80,992 | 82,704 |
Total Current and Deferred | (23,667) | 73,367 | 59,101 |
Discontinued Operation, Tax Effect of Discontinued Operation | $ (2,618) | $ (8,413) | $ (48,626) |
Income Taxes_ Deferred Income T
Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Tax Assets, Net [Abstract] | ||
Regulatory liabilities | $ 92,966 | $ 90,742 |
Employee benefits | 14,039 | 18,724 |
Federal net operating loss | 139,371 | 155,276 |
Other deferred tax assets | 101,579 | 74,561 |
Less: Valuation allowance | (11,809) | (9,121) |
Total deferred tax assets | 336,146 | 330,182 |
Deferred tax liabilities: | ||
Accelerated depreciation, amortization and other plant-related differences | (529,338) | (510,774) |
Regulatory assets | (32,324) | (26,245) |
Goodwill | (602) | (46,392) |
State deferred tax liability | (64,095) | (58,930) |
Deferred costs | (13,351) | (16,063) |
Other deferred tax liabilities | (7,767) | (8,298) |
Total deferred tax liabilities | (647,477) | (666,702) |
Net deferred tax liability | $ 311,331 | $ 336,520 |
Income Taxes_ Effective Tax Rat
Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Federal Statutory Rate | 21.00% | 35.00% | 35.00% |
State income tax (net of federal tax effect) | 2.30% | 0.90% | 1.20% |
Percentage depletion | (0.40%) | (0.60%) | (0.80%) |
Non-controlling interest | (1.30%) | (1.80%) | (1.60%) |
Equity AFUDC | 0.00% | (0.20%) | (0.50%) |
Tax credits | (2.00%) | (1.70%) | (0.40%) |
Transaction costs | 0.00% | 0.00% | 0.50% |
Accounting for uncertain tax positions adjustment | 0.00% | (0.20%) | (2.70%) |
Flow-through adjustments | (1.60%) | (1.10%) | (2.10%) |
Jurisdictional simplification project | (28.50%) | 0.00% | 0.00% |
Other tax differences | (0.40%) | (0.90%) | 0.10% |
IRC 172(f) carryback claim | 0.00% | (0.70%) | 0.00% |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 1.60% | (2.70%) | 0.00% |
Effective Income Tax Rate, Continuing Operations | (9.30%) | 26.00% | 28.70% |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | $ 4 | $ 8 |
Income Taxes_ Net Operating Los
Income Taxes: Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating Loss Carryforwards [Line Items] | |||
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 |
Deferred Tax Assets, Operating Loss Carryforwards | 139,371 | $ 155,276 | |
Internal Revenue Service (IRS) | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 663,741 | ||
State and Local Jurisdiction | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 542,632 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 3,500 | ||
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards Valuation Allowance | 400 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 400 | ||
Valuation Allowance Reduction due to Expired NOL | 1,200 | ||
Deferred Income Tax Expense (Benefit) | 400 | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 1,200 |
Income Taxes_ Reconciliation of
Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Liability for Uncertain Tax Positions, Noncurrent, Period Start | $ 3,263 | $ 3,592 | $ 31,986 |
Additions for prior year tax positions | 251 | 358 | 2,423 |
Reductions for prior year tax positions | (417) | (5,713) | (19,174) |
Additions for current year tax positions | 486 | 5,026 | 0 |
Settlements | 0 | 0 | (11,643) |
Liability for Uncertain Tax Positions, Noncurrent, Period End | 3,583 | $ 3,263 | $ 3,592 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | $ 100 |
Income Taxes_ Interest, Penalti
Income Taxes: Interest, Penalties and Audits (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Examination [Line Items] | |||
Deferred Income Tax Expense (Benefit) | $ (24,239,000) | $ 80,992,000 | $ 82,704,000 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | 0 | $ 11,643,000 |
Unrecognized Tax Benefits, Interest Expense | 0 | 0 | |
Unrecognized Tax Benefits, Interest Accrued | 0 | $ 0 | |
Like-Kind Exchange, Aquila and IPP Transactions | |||
Income Tax Examination [Line Items] | |||
Deferred Income Tax Expense (Benefit) | 125,000,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 29,000,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities - Reducing Accumulated Deferred Income Taxes | 17,000,000 | ||
Unrecognized Tax Benefits, Decrease From Settlements With Taxing Authorities - Reclassified to Current Taxes Payable | $ 12,000,000 |
Income Taxes_ Carryforwards, St
Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Tax Credit Carryforward [Line Items] | |||
Income Tax Expense (Benefit) | $ (23,667) | $ 73,367 | $ 59,101 |
State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Valuation Allowance | 11,000 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 3,500 | ||
State and Local Jurisdiction | Investment Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | 20,285 | ||
State and Local Jurisdiction | Research Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | 180 | ||
State and Local Jurisdiction | Deferred Tax Asset | |||
Tax Credit Carryforward [Line Items] | |||
Income Tax Expense (Benefit) | 1,900 | ||
State and Local Jurisdiction | Deferred Tax Asset | Utilities Group | |||
Tax Credit Carryforward [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 1,600 | ||
Valuation Allowance, Operating Loss Carryforwards | State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 400 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest expense | $ 143,720 | $ 140,533 | $ 139,091 |
Fuel, purchased power and cost of natural gas sold | 625,610 | 563,288 | 499,132 |
Operations and maintenance | 481,706 | 454,605 | 426,603 |
Income before income taxes | 255,882 | 281,742 | 205,894 |
Income Tax Expense (Benefit) | 23,667 | (73,367) | (59,101) |
Net income | 272,662 | 191,276 | $ 82,631 |
Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net income | (4,117) | (3,372) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Income before income taxes | (2,981) | (2,271) | |
Income Tax Expense (Benefit) | 630 | 875 | |
Net income | (2,351) | (1,396) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Swap | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Interest expense | (2,851) | (2,941) | |
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net (loss) from discontinued operations | 0 | 913 | |
Fuel, purchased power and cost of natural gas sold | (130) | (243) | |
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net (loss) from discontinued operations | 0 | 29 | |
Operations and maintenance | 178 | 168 | |
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Net (loss) from discontinued operations | 0 | (58) | |
Operations and maintenance | (2,487) | (1,599) | |
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Income before income taxes | (2,309) | (1,460) | |
Income Tax Expense (Benefit) | 543 | (516) | |
Net income | $ (1,766) | $ (1,976) |
Other Comprehensive Income_ Acc
Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | $ (41,202) | $ (34,883) |
Reclassification from Legal Entity Restructuring | 6,519 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (26,916) | (41,202) |
Accumulated Defined Benefit Plans Adjustment | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (21,103) | (16,541) |
before reclassifications | 2,155 | (1,890) |
Reclassification from Legal Entity Restructuring | 6,519 | |
Reclassification of certain tax effects from AOCI | 726 | (3,616) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (9,937) | (21,103) |
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 1,766 | 944 |
Accumulated Other Comprehensive Income (Loss) | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
before reclassifications | 2,910 | (1,659) |
Reclassification from Legal Entity Restructuring | 6,519 | |
Reclassification of certain tax effects from AOCI | 740 | (7,000) |
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 4,117 | 2,340 |
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (19,581) | (18,109) |
before reclassifications | 0 | 0 |
Reclassification from Legal Entity Restructuring | 0 | |
Reclassification of certain tax effects from AOCI | 22 | (3,384) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (17,307) | (19,581) |
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | 2,252 | 1,912 |
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (518) | (233) |
before reclassifications | 755 | 231 |
Reclassification from Legal Entity Restructuring | 0 | |
Reclassification of certain tax effects from AOCI | (8) | 0 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | 328 | (518) |
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Amounts reclassified from AOCI | $ 99 | $ (516) |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Non-cash investing activities and financing from continuing operations - | |||
Property, plant and equipment acquired with accrued liabilities | $ 69,017 | $ 28,191 | $ 27,034 |
Increase (decrease) in capitalized assets associated with asset retirement obligations | 2,625 | 3,198 | 8,577 |
Cash (paid) refunded during the period for continuing operations- | |||
Interest (net of amount capitalized) | (137,965) | (132,428) | (113,627) |
Income taxes (paid) refunded | $ (14,730) | $ 1,775 | $ (1,156) |
Employee Benefit Plans_ Narrati
Employee Benefit Plans: Narrative (Details) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Maximum Annual Contribution Per Employee, Percent | 50.00% | |
Employers Matching Contribution, Annual Vesting Percentage | 20.00% | |
Employee Vesting Period | 5 years | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 100.00% | 100.00% |
Hedge Funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 5.00% | 6.00% |
Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employers Matching Contribution, Annual Vesting Percentage | 100.00% | |
Pension Plans, Defined Benefit | Minimum | Return Seeking Assets | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 29.00% | |
Pension Plans, Defined Benefit | Minimum | Hedge Funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 63.00% | |
Pension Plans, Defined Benefit | Maximum | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 71.00% | |
Pension Plans, Defined Benefit | Maximum | Return Seeking Assets | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 37.00% |
Employee Benefit Plans_ Plan As
Employee Benefit Plans: Plan Assets Allocation (Details) | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 100.00% | 100.00% |
Equity Securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 17.00% | 26.00% |
Real Estate | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 4.00% | 4.00% |
Fixed Income Funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 71.00% | 63.00% |
Cash and Cash Equivalents | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 3.00% | 1.00% |
Hedge Funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 5.00% | 6.00% |
Employee Benefit Plans_ Plan Co
Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year | $ 13,000 | |
Pension Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | 12,700 | $ 27,700 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | 5,298 | 4,332 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Payment for Pension and Other Postretirement Benefits | 2,073 | 3,217 |
Defined Contribution Plan, Company Retirement | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Employer Contributions | 8,766 | 10,223 |
Defined Contribution Plan, 401K | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Employer Contributions | $ 13,559 | $ 9,811 |
Employee Benefit Plans_ Employe
Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Hedge Funds | Minimum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Percentage Of Monthly Redemption | 20.00% | ||
Hedge Funds | Maximum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Percentage Of Quarterly Redemption | 100.00% | ||
Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 390,796 | $ 416,343 | $ 364,695 |
Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 8,162 | 8,621 | $ 8,470 |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 390,796 | 416,343 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 358,462 | 377,017 | |
Alternative Investment, Fair Value Disclosure | 32,334 | 39,326 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,867 | 1,280 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 1,867 | 1,280 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 9,923 | 2,184 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 9,923 | 2,184 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 67,457 | 109,496 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 67,457 | 109,496 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 279,148 | 262,329 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 279,148 | 262,329 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 13,618 | 17,429 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 67 | 1,728 | |
Alternative Investment, Fair Value Disclosure | 13,551 | 15,701 | |
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 18,783 | 23,625 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 0 | 0 | |
Alternative Investment, Fair Value Disclosure | 18,783 | 23,625 | |
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 8,162 | 8,621 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 8,162 | 8,621 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 4,873 | 4,671 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 4,873 | 4,671 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,005 | 1,374 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 1,005 | 1,374 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 2,284 | 2,576 | |
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments | 2,284 | 2,576 | |
Alternative Investment, Fair Value Disclosure | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 5,878 | 6,045 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 4,873 | 4,671 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,005 | 1,374 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 358,462 | 377,017 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 1,867 | 1,280 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 9,923 | 2,184 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 67,457 | 109,496 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 279,148 | 262,329 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 67 | 1,728 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 2,284 | 2,576 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 2,284 | 2,576 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Fixed Income Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | 0 | 0 | |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Plan Assets, Amount | $ 0 | $ 0 | |
Hedge Funds | Minimum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investment Redemption, Notice Period | 10 days | ||
Hedge Funds | Maximum | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Investment Redemption, Notice Period | 45 days |
Employee Benefit Plans_ Changes
Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plans, Defined Benefit | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | $ 474,725 | $ 440,179 | |
Service cost | 6,834 | 7,034 | $ 7,619 |
Interest cost | 15,470 | 15,520 | 15,743 |
Actuarial (gain) loss | (31,340) | 36,661 | |
Amendments | 0 | 0 | |
Benefits paid | (20,308) | (24,669) | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 445,381 | 474,725 | 440,179 |
Supplemental Employee Retirement Plans, Defined Benefit | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 45,112 | 43,869 | |
Service cost | 1,764 | 2,937 | |
Interest cost | 1,170 | 1,276 | |
Actuarial (gain) loss | (2,963) | 247 | |
Amendments | 0 | 0 | |
Benefits paid | (2,073) | (3,217) | |
Plan participants’ contributions | 0 | 0 | |
Projected benefit obligation at end of year | 43,010 | 45,112 | 43,869 |
Other Postretirement Benefit Plans, Defined Benefit | |||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Projected benefit obligation at beginning of year | 69,339 | 68,023 | |
Service cost | 2,291 | 2,300 | 1,757 |
Interest cost | 2,085 | 2,141 | 1,942 |
Actuarial (gain) loss | (9,045) | (396) | |
Amendments | 0 | 265 | |
Benefits paid | (5,298) | (4,332) | |
Plan participants’ contributions | 1,445 | 1,338 | |
Projected benefit obligation at end of year | $ 60,817 | $ 69,339 | $ 68,023 |
Employee Benefit Plans_ Chang_2
Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning fair value of plan assets | $ 416,343 | $ 364,695 |
Investment income (loss) | (17,939) | 48,617 |
Employer contributions | 12,700 | 27,700 |
Retiree contributions | 0 | 0 |
Benefits paid | (20,308) | (24,669) |
Ending fair value of plan assets | 390,796 | 416,343 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning fair value of plan assets | 0 | 0 |
Investment income (loss) | 0 | 0 |
Employer contributions | 2,073 | 3,217 |
Retiree contributions | 0 | 0 |
Benefits paid | (2,073) | (3,217) |
Ending fair value of plan assets | 0 | 0 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning fair value of plan assets | 8,621 | 8,470 |
Investment income (loss) | (149) | 120 |
Employer contributions | 3,543 | 3,025 |
Retiree contributions | 1,445 | 1,338 |
Benefits paid | (5,298) | (4,332) |
Ending fair value of plan assets | $ 8,162 | $ 8,621 |
Employee Benefit Plans_ Amounts
Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | $ 284,235 | $ 297,454 |
Non-current liabilities | 145,147 | 159,646 |
Regulatory liabilities | 540,794 | 485,126 |
Pension Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | 82,919 | 72,756 |
Current liabilities | 0 | 0 |
Non-current assets | 0 | 0 |
Non-current liabilities | 54,585 | 58,381 |
Regulatory liabilities | 4,620 | 5,232 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | 0 | 0 |
Current liabilities | 1,463 | 1,372 |
Non-current assets | 0 | 0 |
Non-current liabilities | 41,547 | 43,739 |
Regulatory liabilities | 0 | 0 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | 6,655 | 11,507 |
Current liabilities | 3,885 | 4,423 |
Non-current assets | 249 | 69 |
Non-current liabilities | 49,015 | 56,365 |
Regulatory liabilities | $ 5,207 | $ 3,334 |
Employee Benefit Plans_ Accumul
Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Pension Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 428,851 | $ 450,394 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | 40,530 | 41,243 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 60,817 | $ 69,339 |
Employee Benefit Plans_ Compone
Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 6,834 | $ 7,034 | $ 7,619 |
Interest cost | 15,470 | 15,520 | 15,743 |
Expected return on assets | (24,741) | (24,517) | (23,062) |
Net amortization of prior service cost | 58 | 58 | 58 |
Recognized net actuarial loss (gain) | 8,632 | 4,007 | 7,173 |
Settlement Expense | 0 | 0 | 10 |
Net periodic benefit expense | 6,253 | 2,102 | 7,541 |
Supplemental Non-qualified Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 1,764 | 1,546 | 1,335 |
Interest cost | 1,170 | 1,276 | 1,257 |
Expected return on assets | 0 | 0 | 0 |
Net amortization of prior service cost | 2 | 2 | 2 |
Recognized net actuarial loss (gain) | 1,000 | 1,001 | 829 |
Settlement Expense | 0 | 0 | 0 |
Net periodic benefit expense | 3,936 | 3,825 | 3,423 |
Other Postretirement Benefit Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 2,291 | 2,300 | 1,757 |
Interest cost | 2,085 | 2,141 | 1,942 |
Expected return on assets | (315) | (315) | (279) |
Net amortization of prior service cost | (398) | (411) | (428) |
Recognized net actuarial loss (gain) | 216 | 499 | 335 |
Settlement Expense | 0 | 0 | |
Net periodic benefit expense | $ 3,879 | $ 4,214 | $ 3,327 |
Employee Benefit Plans_ Accum_2
Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Pension Plans, Defined Benefit | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Net (gain) loss | $ 11,967 | $ 10,056 |
Prior service cost (gain) | 1 | 21 |
Reclassification of certain tax effects from AOCI | (594) | 2,087 |
Reclassification to regulatory asset | (5,600) | 0 |
Total AOCI | 5,774 | 12,164 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Net (gain) loss | 4,668 | 6,639 |
Prior service cost (gain) | 3 | 4 |
Reclassification of certain tax effects from AOCI | (87) | 1,371 |
Reclassification to regulatory asset | 0 | 0 |
Total AOCI | 4,584 | 8,014 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract] | ||
Net (gain) loss | 860 | 1,309 |
Prior service cost (gain) | (317) | (542) |
Reclassification of certain tax effects from AOCI | (45) | 158 |
Reclassification to regulatory asset | (919) | 0 |
Total AOCI | $ (421) | $ 925 |
Employee Benefit Plans_ Defined
Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Healthcare trend rate pre-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Year Ultimate Trend Reached | 2,027 | 2,027 | |
Healthcare trend rate post-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Year Ultimate Trend Reached | 2,026 | 2,026 | |
Black Hills Corporation - All Plans | Healthcare trend rate pre-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 6.70% | 7.00% | |
Black Hills Corporation - All Plans | Healthcare trend rate post-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 4.94% | 5.00% | |
Black Hills Service Company | Healthcare trend rate pre-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Ultimate trend rate | 4.50% | 4.50% | |
Black Hills Service Company | Healthcare trend rate post-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Ultimate trend rate | 4.50% | 4.50% | |
Pension Plans, Defined Benefit | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 4.40% | 3.71% | 4.27% |
Rate of Increase in Compensation Levels | 3.52% | 3.43% | 3.47% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Expected Long-term Return on Assets | 6.25% | 6.75% | 6.87% |
Rate of Compensation Increase | 3.43% | 3.47% | 3.42% |
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year | 6.00% | ||
Pension Plans, Defined Benefit | Black Hills Corporation Pension Plan | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 4.40% | ||
Pension Plans, Defined Benefit | Black Hills Corporation - All Plans | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.71% | 4.27% | 4.50% |
Supplemental Employee Retirement Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 4.34% | 3.56% | 4.02% |
Rate of Increase in Compensation Levels | 5.00% | 5.00% | 5.00% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Rate of Compensation Increase | 5.00% | 5.00% | 5.00% |
Supplemental Employee Retirement Plan | Black Hills Corporation - All Plans | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.67% | 4.02% | 4.28% |
Other Postretirement Benefit Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 4.28% | 3.60% | 3.96% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Expected Long-term Return on Assets | 3.93% | 3.88% | 3.83% |
Other Postretirement Benefit Plan | Black Hills Corporation - All Plans | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 3.60% | 4.05% | 4.18% |
Employee Benefit Plans_ Project
Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Pension Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,019 | $ 24,405 |
2,020 | 25,847 |
2,021 | 26,951 |
2,022 | 27,972 |
2,023 | 29,002 |
2024-2028 | 151,915 |
Supplemental Employee Retirement Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,019 | 1,463 |
2,020 | 1,406 |
2,021 | 1,617 |
2,022 | 1,727 |
2,023 | 1,912 |
2024-2028 | 12,208 |
Other Postretirement Benefit Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2,019 | 4,898 |
2,020 | 5,545 |
2,021 | 5,695 |
2,022 | 5,849 |
2,023 | 5,607 |
2024-2028 | $ 24,953 |
Power Purchase and Transmission
Power Purchase and Transmission Services Agreements (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2018USD ($)MW | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 11, 2018 | |
Long-term Purchase Commitment [Line Items] | ||||
Number of Megawatts Capacity Sold | 40 | |||
AltaGas | ||||
Long-term Purchase Commitment [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |||
Busch Ranch I Wind Farm | Black Hills Electric Generation and Colorado Electric | ||||
Long-term Purchase Commitment [Line Items] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 100.00% | |||
Busch Ranch I Wind Farm | AltaGas | ||||
Long-term Purchase Commitment [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |||
Sharing Arrangement with the City of Gillette, Wyoming | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Purchase Commitment, Period | 20 years | |||
PacifiCorp Purchase Power Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2023 | |||
Megawatts of Capacity Purchased | 50 | |||
Cost of Purchased Power | $ | $ 13,681 | $ 13,218 | $ 12,221 | |
PacifiCorp Transmission | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2023 | |||
Megawatts of Capacity Purchased | 50 | |||
Cost of Purchased Power | $ | $ 1,742 | 1,671 | 1,428 | |
Happy Jack Wind Purchase Power Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts of Capacity Purchased | 29.5 | |||
Happy Jack Wind Purchase Power Agreement | Subsidiary of Common Parent | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Sep. 3, 2028 | |||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 49.83051% | |||
Happy Jack Wind Purchase Power Agreement | Renewable Wind Energy, Wyoming Electric | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Power | $ | $ 3,884 | 3,846 | 3,836 | |
Silver Sage Wind Power Purchase Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Sep. 30, 2029 | |||
Megawatts of Capacity Purchased | 30 | |||
Silver Sage Wind Power Purchase Agreement | Renewable Wind Energy, Wyoming Electric | ||||
Long-term Purchase Commitment [Line Items] | ||||
Megawatts of Capacity Purchased | 20 | |||
Cost of Purchased Power | $ | $ 5,376 | 4,934 | 4,949 | |
Platte River Power Authority Wind Power Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Sep. 30, 2029 | |||
Megawatts of Capacity Purchased | 12 | |||
Cost of Purchased Power | $ | $ 223 | 0 | 0 | |
Cargill Power Purchase Agreement | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Power | $ | $ 0 | 0 | 10,995 | |
Busch Ranch I Wind Farm | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Oct. 1, 2037 | |||
Megawatts of Capacity Purchased | 14.5 | |||
Cost of Purchased Power | $ | $ 0 | $ 1,966 | $ 2,071 |
Commitments And Contingencies_
Commitments And Contingencies: Power Purchase Agreement - Related Party (Details) - MW | Dec. 11, 2018 | Dec. 31, 2018 |
Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Utility Plant, Megawatt Capacity | 29 | |
Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Number of Megawatts Capacity Purchased | 14.5 | |
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Oct. 1, 2037 | |
AltaGas | ||
Long-term Purchase Commitment [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
AltaGas | Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% |
Commitments And Contingencies_2
Commitments And Contingencies: Other Gas Supply Agreements (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Purchase Commitment | |
Long-term Purchase Commitment [Line Items] | |
Long Term Contract For Purchase of Fuel, Date of Contract Expiration | Dec. 31, 2044 |
Commitments And Contingencies_3
Commitments And Contingencies: Purchase Commitment (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)MMBTU | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |||
Term of Evergreen Contracts | 60 days | ||
CIG Rockies | |||
Long-term Purchase Commitment [Line Items] | |||
2,019 | 5,803,117 | ||
2,020 | 75,075 | ||
2,021 | 0 | ||
2,022 | 0 | ||
2,023 | 0 | ||
Thereafter | 0 | ||
NNG-Ventura | |||
Long-term Purchase Commitment [Line Items] | |||
2,019 | 3,650,000 | ||
2,020 | 3,660,000 | ||
2,021 | 3,650,000 | ||
2,022 | 1,810,000 | ||
2,023 | 0 | ||
Thereafter | 0 | ||
NWPL-Wyoming | |||
Long-term Purchase Commitment [Line Items] | |||
2,019 | 720,000 | ||
2,020 | 0 | ||
2,021 | 0 | ||
2,022 | 0 | ||
2,023 | 0 | ||
Thereafter | 0 | ||
Other Natural Gas Indices | |||
Long-term Purchase Commitment [Line Items] | |||
2,019 | 236 | ||
2,020 | 0 | ||
2,021 | 0 | ||
2,022 | 0 | ||
2,023 | 0 | ||
Thereafter | 0 | ||
Natural Gas, Distribution | |||
Long-term Purchase Commitment [Line Items] | |||
Natural Gas Purchases | $ | $ 27 | $ 65 | $ 31 |
Commitments And Contingencies_4
Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Power Purchase Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2,019 | $ 22,092 |
2,020 | 6,837 |
2,021 | 6,203 |
2,022 | 6,203 |
2,023 | 6,204 |
Thereafter | 0 |
Transportation, Storage, Gathering And Coal Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2,019 | 129,018 |
2,020 | 127,326 |
2,021 | 118,707 |
2,022 | 92,635 |
2,023 | 73,919 |
Thereafter | $ 148,363 |
Commitments And Contingencies_5
Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility - Purchase Option, Property $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($)MW | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Number of Megawatts Capacity Purchased | MW | 60 |
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2022 |
Asset Purchase Option | $ | $ 2.1 |
Property, Plant and Equipment, Useful Life | 35 years |
Commitments And Contingencies_6
Commitments And Contingencies: Power Sales Agreements (Details) | 12 Months Ended |
Dec. 31, 2018MW | |
M D U, Montana Dakota Utilities | |
Long-term Purchase Commitment [Line Items] | |
Long-term Contract To Sell Electric Power, Date of Contract Expiration | Dec. 31, 2023 |
M D U, Montana Dakota Utilities | Wygen I I I Generating Facility | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 25 |
Long-term Contract To Sell Electric Power, Date of Contract Expiration | Jan. 31, 2023 |
M D U, Montana Dakota Utilities | Maximum | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 50 |
City Of Gillette | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 23 |
Long-term Contract To Sell Electric Power, Date of Contract Expiration | Sep. 3, 2019 |
Purchase Power Contract, MEAN, 10 Megawatts | |
Long-term Purchase Commitment [Line Items] | |
Long-term Contract To Sell Electric Power, Date of Contract Expiration | May 31, 2028 |
Purchase Power Contract, MEAN, 10 Megawatts | Neil Simpson I I | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 10 |
Purchase Power Contract, MEAN, 10 Megawatts | Wygen I I I Generating Facility | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 10 |
Macquarie Energy, LLC Supply Agreement | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 50 |
Long-term Contract To Sell Electric Power, Date of Contract Expiration | Dec. 31, 2021 |
Commitments And Contingencies_7
Commitments And Contingencies: Related Party Lease (Details) - Power purchased - Pueblo Airport Generation | 12 Months Ended |
Dec. 31, 2018MW | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Lease Expiration Date | Dec. 31, 2031 |
Number of Megawatts Capacity Purchased | 200 |
Commitments And Contingencies_8
Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | ||
Long-term debt | $ 544,855 | $ 544,855 |
Industrial Development Revenue Bonds Due 2027 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 10,000 | 10,000 |
Long-term Debt, Maturity Date | Mar. 1, 2027 | |
Industrial Development Revenue Bonds Due 2021 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 7,000 | $ 7,000 |
Long-term Debt, Maturity Date | Sep. 1, 2021 |
Commitments And Contingencies_9
Commitments And Contingencies: Environmental Contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Loss Contingencies [Line Items] | ||
Regulatory assets | $ 284,235 | $ 297,454 |
Electric Utilities | ||
Loss Contingencies [Line Items] | ||
Accrual for Environmental Loss Contingencies | 4,100 | |
Gas Utilities | Manufactured Gas Plant | ||
Loss Contingencies [Line Items] | ||
Insurance Settlements Receivable, Noncurrent | 1,100 | |
Accrual for Environmental Loss Contingencies, Gross | 2,600 | |
Gas Utilities | Manufactured Gas Plant | Minimum | ||
Loss Contingencies [Line Items] | ||
Loss Contingency, Range of Possible Loss | 2,600 | |
Gas Utilities | Manufactured Gas Plant | Maximum | ||
Loss Contingencies [Line Items] | ||
Loss Contingency, Range of Possible Loss | 6,100 | |
Environmental | ||
Loss Contingencies [Line Items] | ||
Regulatory assets | 959 | $ 1,031 |
Environmental | Manufactured Gas Plant | ||
Loss Contingencies [Line Items] | ||
Regulatory assets | $ 1,000 | |
Osage Plant Ash Impoundment | ||
Loss Contingencies [Line Items] | ||
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period | 30 years | |
Osage Plant, Industrial Rubble Landfill | ||
Loss Contingencies [Line Items] | ||
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period | 30 years |
Guarantees (Details)
Guarantees (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 94,490 |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | 54,683 |
Performance Guarantee | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 39,807 |
Discontinued Operations (Detail
Discontinued Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract] | |||||||||||
Other current assets | $ 10,360 | $ 10,360 | |||||||||
Deferred income tax assets, noncurrent, net | 16,966 | 16,966 | |||||||||
Property, plant and equipment, net | 56,916 | 56,916 | |||||||||
Other current liabilities | (18,966) | (18,966) | |||||||||
Other noncurrent liabilities | (22,808) | (22,808) | |||||||||
Net assets | 42,468 | 42,468 | |||||||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | |||||||||||
Revenue | $ 5,897 | 25,382 | $ 34,058 | ||||||||
Operations and maintenance | 11,014 | 22,872 | 27,187 | ||||||||
Loss on sale of assets | 3,259 | 0 | 0 | ||||||||
Depreciation, depletion and amortization | 1,300 | 7,521 | 13,510 | ||||||||
Impairment of long-lived assets | 0 | 20,385 | 106,957 | ||||||||
Total operating expenses | 15,573 | 50,778 | 147,654 | ||||||||
Operating (loss) | (9,676) | (25,396) | (113,596) | ||||||||
Interest income (expense), net | (19) | 181 | 698 | ||||||||
Other income (expense), net | 190 | (297) | 110 | ||||||||
Income tax benefit | 2,618 | 8,413 | 48,626 | ||||||||
(Loss) from discontinued operations | $ (1,260) | $ (857) | $ (2,427) | $ (2,343) | $ (13,614) | $ (1,300) | $ (616) | $ (1,569) | (6,887) | (17,099) | (64,162) |
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) | $ 13,000 | ||||||||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | |||||||||||
Impairment of long-lived assets | $ 20,000 | $ 92,000 |
Discontinued Operations_ Impair
Discontinued Operations: Impairment of Long-Lived Assets (Details) $ in Thousands | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2016USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)$ / bbl$ / MMcf | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Impairment of long-lived assets | $ 0 | $ 20,385 | $ 106,957 | |
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] | ||||
Impairment of long-lived assets | $ 20,000 | $ 92,000 | ||
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 | |||
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 | |||
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 | |||
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 | |||
Results of Operations, Impairment of Oil and Gas Properties | $ 106,957 | |||
Discontinued Operations, Held-for-sale or Disposed of by Sale | Assets Not Expected To Be Utilized In Cost Of Service Gas Program | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Results of Operations, Impairment of Oil and Gas Properties | $ 14,000 |
Oil and Gas Reserves (Unaudit_2
Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |
Proved Reserves | $ 0 |
Unproved Reserves | 910 |
Exploration Costs | 1,102 |
Development Costs | 4,657 |
Asset Retirement Obligation Incurred | 0 |
Oil and Gas Property Acquisition, Exploration, and Development Activities | $ 6,669 |
Oil and Gas Reserves (Unaudit_3
Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details) | 12 Months Ended |
Dec. 31, 2016$ / bbl$ / MMcfMMcfMBbls | |
Reserve Quantities [Line Items] | |
Discounted Present Value Rate Used in Estimating Future Net Revenues - Oil and Gas Industry | 10.00% |
Discontinued Operations, Held-for-sale or Disposed of by Sale | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 |
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 |
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 |
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | Piceance Basin | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 1.54 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | San Juan Basin | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 0.92 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | Other Basin's | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 0.53 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | Oil | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Balance at Beginning of Year | MBbls | 3,450 |
Production | MBbls | (319) |
Additions, Acquisitions (Sales) | MBbls | (570) |
Additions, Extensions, Discoveries (bcfe) | MBbls | 3 |
Reserves, Revisions of Previous Estimates | MBbls | (322) |
Balance at End of Year | MBbls | 2,242 |
Proved Developed Reserves (Volume) | MBbls | 2,242 |
Proved Undeveloped Reserve (Volume) | MBbls | 0 |
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 |
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | Natural Gas | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Balance at Beginning of Year | 73,412 |
Production | (9,430) |
Additions, Acquisitions (Sales) | (1,291) |
Additions, Extensions, Discoveries (bcfe) | 52 |
Reserves, Revisions of Previous Estimates | (8,173) |
Balance at End of Year | 54,570 |
Proved Developed Reserves (Volume) | 54,570 |
Proved Undeveloped Reserve (Volume) | 0 |
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 |
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 |
Discontinued Operations, Held-for-sale or Disposed of by Sale | Natural Gas Liquids | |
Proved Developed And Undeveloped Reserves [Roll Forward] | |
Balance at Beginning of Year | 1,752 |
Production | (133) |
Additions, Acquisitions (Sales) | (17) |
Additions, Extensions, Discoveries (bcfe) | 0 |
Reserves, Revisions of Previous Estimates | 110 |
Balance at End of Year | 1,712 |
Proved Developed Reserves (Volume) | 1,712 |
Proved Undeveloped Reserve (Volume) | 0 |
Average Natural Gas Liquids Price Per MCF, NYMEX | $ / MMcf | 0 |
Average Natural Gas Liquids Price Per MCF, Wellhead | $ / MMcf | 11.92 |
Cawley Gillespie & Associates - Mr. Zane Meekins | |
Reserve Quantities [Line Items] | |
Practical Experience In Petroleum Engineering | 31 years |
Experience In Estimation and Evaluation of Reserves | 29 years |
Oil and Gas Reserves (Unaudit_4
Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands | Dec. 31, 2016USD ($) |
Unproved oil and gas properties | $ 18,547 |
Proved oil and gas properties | 1,043,558 |
Gross capitalized costs | 1,062,105 |
Accumulated depreciation, depletion and amortization and valuation allowances | (1,000,091) |
Net capitalized costs | $ 62,014 |
Oil and Gas Reserves (Unaudit_5
Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Revenue | $ 34,058 |
Production costs | 17,231 |
Depreciation, depletion and amortization | 12,574 |
Impairment of long-lived assets | 106,957 |
Total costs | 136,762 |
Results of operations from producing activities before tax | (102,704) |
Income tax benefit (expense) | 37,916 |
Results of operations from producing activities (excluding general and administrative costs and interest costs) | $ (64,788) |
Oil and Gas Reserves (Unaudit_6
Oil and Gas Reserves (Unaudited): Unproved Properties (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |
Interest Costs, Capitalized During Period | $ 900 |
Leasehold acquisition cost | 963 |
Exploration cost | 532 |
Capitalized interest | 50 |
Total | $ 1,545 |
Oil and Gas Reserves (Unaudit_7
Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Future cash inflows | $ 246,221 | |
Future production costs | (166,248) | |
Future development costs, including plugging and abandonment | (18,333) | |
Future net cash flows | 61,640 | |
10% annual discount for estimated timing of cash flows | (26,574) | |
Standardized measure of discounted future net cash flows | $ 35,066 | $ 79,028 |
Oil and Gas Reserves (Unaudit_8
Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |
Standardized measure - beginning of year | $ 79,028 |
Sales and transfers of oil and gas produced, net of production costs | (4,314) |
Net changes in prices and production costs | (32,698) |
Changes in future development costs | 1,825 |
Revisions of previous quantity estimates | (7,477) |
Accretion of discount | 7,903 |
Sales of reserves | (9,201) |
Standardized measure - end of year | $ 35,066 |
Quarterly Historical Data (Un_3
Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Selected Quarterly Financial Information [Line Items] | |||||||||||
Revenue - | $ 501,196 | $ 321,979 | $ 355,704 | $ 575,389 | $ 455,298 | $ 335,611 | $ 341,829 | $ 547,528 | $ 1,754,268 | $ 1,680,266 | $ 1,538,916 |
Operating income (loss) | 114,127 | 65,085 | 69,551 | 148,274 | 117,195 | 79,559 | 69,796 | 150,186 | 397,037 | 416,736 | 336,181 |
Income (loss) from continuing operations | 91,604 | 21,801 | 27,167 | 138,977 | 67,835 | 32,898 | 25,927 | 81,715 | 279,549 | 208,375 | 146,793 |
Net (loss) from discontinued operations | (1,260) | (857) | (2,427) | (2,343) | (13,614) | (1,300) | (616) | (1,569) | (6,887) | (17,099) | (64,162) |
Net income attributable to noncontrolling interest | (3,773) | (3,994) | (2,823) | (3,630) | (3,568) | (3,935) | (3,116) | (3,623) | (14,220) | (14,242) | (9,661) |
Net income (loss) available for common stock | 86,571 | 16,950 | 21,917 | 133,004 | 50,653 | 27,663 | 22,195 | 76,523 | 258,442 | 177,034 | 72,970 |
Amounts attributable to common shareholders: | |||||||||||
Net income from continuing operations | 87,831 | 17,807 | 24,344 | 135,347 | 64,267 | 28,963 | 22,811 | 78,092 | 265,329 | 194,133 | 137,132 |
Net (loss) from discontinued operations | (1,260) | (857) | (2,427) | (2,343) | (13,614) | (1,300) | (616) | (1,569) | (6,887) | (17,099) | (64,162) |
Net income (loss) available for common stock | $ 86,571 | $ 16,950 | $ 21,917 | $ 133,004 | $ 50,653 | $ 27,663 | $ 22,195 | $ 76,523 | $ 258,442 | $ 177,034 | $ 72,970 |
Earnings (loss) per share of common stock, Basic - | |||||||||||
Earnings from continuing operations, Basic (usd per share) | $ 1.52 | $ 0.33 | $ 0.46 | $ 2.54 | $ 1.21 | $ 0.54 | $ 0.43 | $ 1.47 | $ 4.88 | $ 3.65 | $ 2.64 |
(Loss) from discontinued operations per share, Basic (usd per share) | (0.02) | (0.02) | (0.05) | (0.05) | (0.26) | (0.02) | (0.01) | (0.03) | (0.13) | (0.32) | (1.23) |
Total earnings (loss) per share of common stock, Basic (usd per share) | 1.50 | 0.32 | 0.41 | 2.49 | 0.95 | 0.52 | 0.42 | 1.44 | 4.75 | 3.33 | 1.41 |
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Earnings from continuing operations, Diluted (usd per share) | 1.51 | 0.32 | 0.45 | 2.50 | 1.17 | 0.52 | 0.41 | 1.42 | 4.78 | 3.52 | 2.57 |
(Loss) from discontinued operations, Diluted (usd per share) | (0.02) | (0.02) | (0.05) | (0.04) | (0.25) | (0.02) | (0.01) | (0.03) | (0.12) | (0.31) | (1.20) |
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 1.49 | $ 0.31 | $ 0.40 | $ 2.46 | $ 0.92 | $ 0.50 | $ 0.40 | $ 1.39 | $ 4.66 | $ 3.21 | $ 1.37 |
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 | ||||||||
Business Combination, Acquisition Related Costs, Net Of Tax | $ 1,300 | $ 200 | $ 300 | $ 900 | |||||||
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Income Tax Expense (Benefit) | 7,600 | ||||||||||
Income Tax Expense (Benefit) | 23,667 | $ (73,367) | $ (59,101) | ||||||||
Discontinued Operations, Held-for-sale or Disposed of by Sale | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Impairment Of Oil And Gas Properties, Net Of Tax | 13,000 | ||||||||||
True-up from SourceGas Tax Returns | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Income Tax Expense (Benefit) | $ 4,100 | ||||||||||
Other Restructuring | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Deferred Income Tax Expense (Benefit) | $ 23,000 | $ 49,000 | $ 73,000 |