Document and Entity Information
Document and Entity Information Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Jan. 31, 2017 | Jun. 30, 2016 | |
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, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
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 | 53,384,259 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $ 3,248,873,889 |
Consolidated Statements of Inco
Consolidated Statements of Income (Loss) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue: | |||
Revenue | $ 1,572,974 | $ 1,304,605 | $ 1,393,570 |
Operating expenses: | |||
Fuel, purchased power and cost of natural gas sold | 499,132 | 456,887 | 581,782 |
Operations and maintenance | 456,399 | 361,109 | 359,095 |
Depreciation, depletion and amortization | 189,043 | 155,370 | 144,745 |
Impairment of long-lived assets | 106,957 | 249,608 | 0 |
Taxes - property, production and severance | 48,522 | 44,353 | 43,580 |
Other operating expenses | 50,335 | 7,483 | 500 |
Total operating expenses | 1,350,388 | 1,274,810 | 1,129,702 |
Operating income | 222,586 | 29,795 | 263,868 |
Interest charges - | |||
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts) | (139,590) | (86,278) | (73,017) |
Allowance for funds used during construction - borrowed | 2,981 | 1,250 | 1,075 |
Capitalized interest | 1,197 | 1,309 | 982 |
Interest income | 1,429 | 1,621 | 1,925 |
Allowance for funds used during construction - equity | 3,270 | 897 | 994 |
Other expense | (609) | (372) | (377) |
Other income | 1,842 | 2,256 | 2,065 |
Total other income (expense) | (129,480) | (79,317) | (66,353) |
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 93,106 | (49,522) | 197,515 |
Equity in earnings (loss) of unconsolidated subsidiaries | 0 | (344) | (1) |
Impairment of equity investments | 0 | (4,405) | 0 |
Income tax benefit (expense) | (10,475) | 22,160 | (66,625) |
Net income (loss) | 82,631 | (32,111) | 130,889 |
Net income attributable to noncontrolling interest | (9,661) | 0 | 0 |
Net income (loss) available for common stock | $ 72,970 | $ (32,111) | $ 130,889 |
Earnings (loss) per share of common stock: | |||
Earnings (loss) per share, Basic (usd per share) | $ 1.41 | $ (0.71) | $ 2.95 |
Earnings (loss) per share, Diluted (usd per share) | $ 1.37 | $ (0.71) | $ 2.93 |
Weighted average common shares outstanding: | |||
Basic (in shares) | 51,922 | 45,288 | 44,394 |
Diluted (in shares) | 53,271 | 45,288 | 44,598 |
Consolidated Statement of Compr
Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net income (loss) | $ 82,631 | $ (32,111) | $ 130,889 |
Other comprehensive income (loss), net of tax: | |||
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax | (1,738) | 2,657 | (10,590) |
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, Net of Tax | (247) | 0 | 237 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), Net of Tax | 1,378 | 1,850 | 646 |
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Net of Tax | (154) | (150) | (141) |
Other comprehensive income (loss), net of tax | (25,828) | 5,989 | 2,378 |
Comprehensive income (loss) | 56,803 | (26,122) | 133,267 |
Net Income (Loss) Attributable to Noncontrolling Interest | (9,661) | 0 | 0 |
Comprehensive income (loss) available for common stock | 47,142 | (26,122) | 133,267 |
Interest Rate Swap | |||
Other comprehensive income (loss), net of tax: | |||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (20,302) | 2,290 | (350) |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 2,534 | 2,299 | 2,313 |
Commodity Contract | |||
Other comprehensive income (loss), net of tax: | |||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (361) | 5,884 | 9,256 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ (6,938) | $ (8,841) | $ 1,007 |
Statement of Comprehensive Inco
Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Benefit plan liability adjustments - net gain (loss), Tax | $ 757 | $ (1,375) | $ 5,004 |
Benefit plan liability adjustments - prior service (costs), Tax | 107 | 0 | (17) |
Reclassification adjustment of benefit plan liability - net gain (loss) tax | (600) | (972) | (348) |
Reclassification adjustment of benefit plan liability - prior service cost, tax | 67 | 88 | 76 |
Interest Rate Swap | |||
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax | 10,920 | (598) | 186 |
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax | (1,365) | (1,348) | (1,356) |
Commodity Contract | |||
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax | 212 | (3,898) | (5,425) |
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax | $ 4,067 | $ 5,619 | $ (988) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 13,580 | $ 440,861 |
Restricted cash and equivalents | 2,274 | 1,697 |
Accounts receivable, net | 263,289 | 147,486 |
Materials, supplies and fuel | 107,210 | 86,943 |
Derivative assets, current | 4,138 | 0 |
Income tax receivable, net | 0 | 368 |
Regulatory assets, current | 49,260 | 57,359 |
Other current assets | 27,063 | 71,763 |
Total current assets | 466,814 | 806,477 |
Investments | 12,561 | 11,985 |
Property, plant and equipment | 6,412,223 | 4,976,778 |
Less accumulated depreciation and depletion | (1,943,234) | (1,717,684) |
Total property, plant and equipment, net | 4,468,989 | 3,259,094 |
Other assets: | ||
Goodwill | 1,299,454 | 359,759 |
Intangible assets, net | 8,392 | 3,380 |
Derivative assets, non-current | 222 | 3,441 |
Regulatory assets, non-current | 246,882 | 175,125 |
Other assets, non-current | 12,130 | 7,382 |
Total other assets, non-current | 1,567,080 | 549,087 |
TOTAL ASSETS | 6,515,444 | 4,626,643 |
Current liabilities: | ||
Accounts payable | 153,477 | 89,794 |
Accrued liabilities | 244,034 | 232,061 |
Derivative liabilities, current | 2,459 | 2,835 |
Accrued income tax, net | 12,552 | 0 |
Regulatory liabilities, current | 13,067 | 4,865 |
Notes payable | 96,600 | 76,800 |
Current maturities of long-term debt | 5,743 | 0 |
Total current liabilities | 527,932 | 406,355 |
Long-term debt, net of current maturities | 3,211,189 | 1,853,682 |
Deferred credits and other liabilities: | ||
Deferred income tax liabilities, net, non-current | 535,606 | 450,579 |
Derivative liabilities, non-current | 274 | 156 |
Regulatory liabilities, non-current | 193,689 | 148,176 |
Benefit plan liabilities | 173,682 | 146,459 |
Other deferred credits and other liabilities | 138,643 | 155,369 |
Total deferred credits and other liabilities | 1,041,894 | 900,739 |
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20) | ||
Redeemable noncontrolling interest | 4,295 | 0 |
Stockholders’ equity - | ||
Common stock $1 par value; 100,000,000 shares authorized; issued: 53,397,467 and 51,231,861 shares, respectively | 53,397 | 51,232 |
Additional paid-in capital | 1,138,982 | 953,044 |
Retained earnings | 457,934 | 472,534 |
Treasury stock at cost - 15,258 and 39,720 shares, respectively | (791) | (1,888) |
Accumulated other comprehensive income (loss) | (34,883) | (9,055) |
Total stockholders’ equity | 1,614,639 | 1,465,867 |
Noncontrolling interest | 115,495 | 0 |
Total equity | 1,730,134 | 1,465,867 |
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY | $ 6,515,444 | $ 4,626,643 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Common Stock, Par Value (usd per share) | $ 1 | $ 1 |
Treasury Stock, Shares | 15,258 | 39,720 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 53,397,467 | 51,231,861 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating activities: | |||
Net income (loss) | $ 82,631 | $ (32,111) | $ 130,889 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 189,043 | 155,370 | 144,745 |
Deferred financing cost amortization | 6,180 | 6,364 | 2,127 |
Impairment of long-lived assets and equity method investments | 106,957 | 254,013 | 0 |
Stock compensation | 10,885 | 4,076 | 9,329 |
Deferred income taxes | 36,217 | (26,028) | 70,232 |
Employee benefit plans | 14,291 | 20,616 | 14,814 |
Other adjustments, net | (5,518) | (4,872) | 14,415 |
Change in certain operating assets and liabilities: | |||
Materials, supplies and fuel | 1,099 | 7,197 | (4,563) |
Accounts receivable, unbilled revenues and other current assets | (28,414) | 40,125 | (18,684) |
Accounts payable and other current liabilities | (40,195) | (4,779) | 7,887 |
Regulatory assets | 3,614 | 21,883 | (38,774) |
Regulatory liabilities | (14,082) | 1,675 | (7,633) |
Contributions to defined benefit pension plans | (14,200) | (10,200) | (10,200) |
Interest rate swap settlement | (28,820) | 0 | 0 |
Other operating activities, net | 775 | (9,034) | 733 |
Net cash provided by operating activities | 320,463 | 424,295 | 315,317 |
Investing activities: | |||
Property, plant and equipment additions | (474,783) | (455,481) | (398,494) |
Acquisition of net assets, net of long-term debt assumed | (1,124,238) | (21,970) | 0 |
Proceeds from sale of assets | 11,418 | 0 | 0 |
Other investing activities | (1,139) | 1,062 | (2,653) |
Net cash provided by (used in) investing activities | (1,588,742) | (476,389) | (401,147) |
Financing activities: | |||
Dividends paid on common stock | (87,570) | (72,604) | (69,636) |
Common stock issued | 121,619 | 248,759 | 3,251 |
Short-term borrowings - issuances | 425,400 | 397,310 | 396,250 |
Short-term borrowings - repayments | (405,600) | (395,510) | (403,750) |
Long-term debt - issuance | 1,767,608 | 300,000 | 160,000 |
Long-term debt - repayments | (1,164,308) | (275,000) | (12,200) |
Sale of noncontrolling interest | 216,370 | 0 | 0 |
Distributions to noncontrolling interests | (9,561) | 0 | 0 |
Equity units - issuance | 0 | 290,030 | 0 |
Other financing activities | (22,960) | (9,283) | 17,152 |
Net cash provided by (used in) financing activities | 840,998 | 483,702 | 91,067 |
Net change in cash and cash equivalents | (427,281) | 431,608 | 5,237 |
Cash and cash equivalents: | |||
Cash and cash equivalents beginning of year | 440,861 | 9,253 | 4,016 |
Cash and cash equivalents end of year | $ 13,580 | $ 440,861 | $ 9,253 |
Consolidated Statement Of Equit
Consolidated Statement Of Equity - USD ($) $ in Thousands | Total | Common Stock | Treasury Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interest [Member] |
Total equity at Dec. 31, 2013 | $ 1,283,500 | $ 44,550 | $ (1,968) | $ 742,344 | $ 515,996 | $ (17,422) | $ 0 |
Common Stock, Shares, Outstanding at Dec. 31, 2013 | 44,550,239 | ||||||
Treasury Stock, Shares at Dec. 31, 2013 | 50,877 | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) available for common stock | 130,889 | 130,889 | |||||
Net income attributable to noncontrolling interest | 0 | ||||||
Net income (loss) | 130,889 | ||||||
Other comprehensive income (loss), net of tax | 2,378 | 2,378 | |||||
Dividends on common stock | (69,636) | (69,636) | |||||
Share-based compensation | 4,415 | $ 112 | $ 93 | 4,210 | |||
Share-based compensation, Shares | 111,507 | (8,651) | |||||
Tax effect of share-based compensation | (499) | (499) | |||||
Dividend reinvestment and stock purchase plan | 2,878 | $ 52 | 2,826 | ||||
Dividend reinvestment and stock purchase plan, shares issued | 52,326 | ||||||
Other stock transactions | (41) | (41) | |||||
Total equity at Dec. 31, 2014 | $ 1,353,884 | $ 44,714 | $ (1,875) | 748,840 | 577,249 | (15,044) | 0 |
Common Stock, Shares, Outstanding at Dec. 31, 2014 | 44,714,072 | ||||||
Treasury Stock, Shares at Dec. 31, 2014 | 42,226 | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.56 | ||||||
Net income (loss) available for common stock | $ (32,111) | (32,111) | |||||
Net income attributable to noncontrolling interest | 0 | ||||||
Net income (loss) | (32,111) | ||||||
Other comprehensive income (loss), net of tax | 5,989 | 5,989 | |||||
Dividends on common stock | (72,604) | (72,604) | |||||
Share-based compensation | 4,240 | $ 127 | $ (13) | 4,126 | |||
Share-based compensation, Shares | 126,765 | (2,506) | |||||
Issuance of common stock | 254,581 | $ 6,325 | 248,256 | ||||
Issuance of common stock, shares | 6,325,000 | ||||||
Issuance costs | (17,926) | (17,926) | |||||
Premium on Equity Units | (33,118) | (33,118) | |||||
Dividend reinvestment and stock purchase plan | 2,957 | $ 66 | 2,891 | ||||
Dividend reinvestment and stock purchase plan, shares issued | 66,024 | ||||||
Other stock transactions | (25) | (25) | |||||
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 | 39,720 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.62 | ||||||
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 | 5,479 | $ 146 | $ 668 | 4,665 | |||
Share-based compensation, Shares | 145,634 | (16,165) | |||||
Issuance of common stock | 119,990 | $ 1,969 | 118,021 | ||||
Issuance of common stock, shares | 1,968,738 | ||||||
Issuance costs | (1,566) | (1,566) | |||||
Dividend reinvestment and stock purchase plan | 2,983 | $ 50 | 2,933 | ||||
Dividend reinvestment and stock purchase plan, shares issued | 51,234 | ||||||
Other stock transactions | 476 | $ 429 | 47 | ||||
Other stock transactions, shares | (8,297) | ||||||
Sale of noncontrolling interest | 177,233 | 61,838 | 115,395 | ||||
Distributions to noncontrolling interest | (9,561) | (9,561) | |||||
Total equity at Dec. 31, 2016 | $ 1,730,134 | $ 53,397 | $ (791) | $ 1,138,982 | $ 457,934 | $ (34,883) | $ 115,495 |
Common Stock, Shares, Outstanding at Dec. 31, 2016 | 53,397,467 | ||||||
Treasury Stock, Shares at Dec. 31, 2016 | 15,258 | 15,258 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Dividends per share paid (usd per share) | $ 1.68 |
Business Description And Signif
Business Description And Significant Accounting Policies: | 12 Months Ended |
Dec. 31, 2016 | |
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, vertically-integrated 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, Mining, and Oil and Gas. 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. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. 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 South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. 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. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program. For further descriptions of our reportable business segments, see Note 5 . The following changes have been made to our Consolidated Statements of Income (Loss) to reflect combined revenue and combined operations and maintenance expenses, rather than by business group as previously reported, for the twelve months ended December 31, 2015 and December 31, 2014 respectively: Year Ended December 31, 2015 Year Ended December 31, 2014 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Revenue: Utilities $ 1,219,526 $ (1,219,526 ) $ — $ 1,300,969 $ (1,300,969 ) $ — Non-regulated energy $ 85,079 $ (85,079 ) $ — $ 92,601 $ (92,601 ) $ — Revenue $ — $ 1,304,605 $ 1,304,605 $ — $ 1,393,570 $ 1,393,570 Operating Expenses: Utilities - operations and maintenance $ 272,407 $ (272,407 ) $ — $ 270,954 $ (270,954 ) $ — Non-regulated energy operations and maintenance $ 88,702 $ (88,702 ) $ — $ 88,141 $ (88,141 ) $ — Operations and maintenance $ — $ 361,109 $ 361,109 $ — $ 359,095 $ 359,095 This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows. Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015 , Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 5 for Revenues and Net Income amounts reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 and December 31, 2014 ; and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 . This segment reclassification did not impact our consolidated financial position, results of operations or cash flows. Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash and book overdrafts. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million , $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the consolidated balance sheet as of December 31, 2015 and to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported. 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. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company 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 working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. 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 so, 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 VIEs 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 it 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 We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash. 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, Oil and Gas, and Power Generation business segments consists of amounts due from sales of coal, crude oil and natural gas, 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): 2016 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Oil and Gas 3,991 — (13 ) 3,978 Corporate 2,228 — — 2,228 Total $ 140,889 $ 124,792 $ (2,392 ) $ 263,289 2015 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,330 32,869 (1,001 ) 62,198 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,026 — — 1,026 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 ________________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015 , previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment. Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. 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 (in thousands): December 31, 2016 December 31, 2015 Materials and supplies $ 68,456 $ 55,726 Fuel - Electric Utilities 3,667 5,567 Natural gas in storage 35,087 25,650 Total materials, supplies and fuel $ 107,210 $ 86,943 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 valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2016 December 31, 2015 Accrued employee compensation, benefits and withholdings $ 56,926 $ 43,342 Accrued property taxes 40,004 32,393 Accrued payments related to litigation expenses and settlements — 38,750 Customer deposits and prepayments 51,628 53,496 Accrued interest and contract adjustment payments 45,503 25,762 Other (none of which is individually significant) 49,973 38,318 Total accrued liabilities $ 244,034 $ 232,061 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 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 class 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. Oil and Gas Operations We account for our oil and gas activities under the full cost method. 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. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length. 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. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31, 2016. See information on our oil and gas drilling activities in Note 21 . Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories. 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. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. 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 and long-term earnings and merger multiples for comparable companies. 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. Goodwill at our Electric utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million , or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million , or 28% of the transaction, to the Gas Utilities. 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 (a) Gas Utilities (a) Power Generation Total Ending balance at December 31, 2014 $ 248,479 $ 96,152 $ 8,765 $ 353,396 Additions (b) — 6,363 — 6,363 Ending balance at December 31, 2015 $ 248,479 $ 102,515 $ 8,765 $ 359,759 Additions (c) — 939,695 — 939,695 Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 _________________ (a) Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details. (b) Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. (c) Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. Our intangible assets represent easements, rights-of-way, customer listings, and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized from 2 years up to 40 years . Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2016 2015 2014 Intangible assets, net, beginning balance $ 3,380 $ 3,176 $ 3,397 Additions 5,522 434 — Amortization expense (a) (510 ) (230 ) (221 ) Intangible assets, net, ending balance $ 8,392 $ 3,380 $ 3,176 _________________ (a) 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, other than Oil and Gas. For the Oil and Gas segment, 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 depleted pursuant to our use of the full cost method. Additional information is included in Note 8 . Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Oil and Gas Segment: • The commodity contracts for the Oil and Gas segment are valued under the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure. Electric Utilities and Gas Utilities Segments: • The commodity contracts for the 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 exchanged-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 option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market data where market data for pricing is observable. In addition, the fair value for the over-the-counter swaps and option derivatives 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. Corporate Segment: • The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for |
Acquisition_
Acquisition: | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisition | ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 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 and $10 million for the years ending December 31, 2016 and 2015, respectively. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses and Interest expense on the Consolidated Statements of Income (Loss). Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income (loss) 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. From the time of acquisition through December 31, 2016 , we decreased goodwill by $6.7 million , reflecting the working capital adjustment received of $11 million and 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 as set forth below: The APSC order includes a twelve -month base rate moratorium, an annual $0.25 million customer credit for a term of up to five years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The CPUC order includes a two -year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three -year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five -years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The NPSC order includes a three -year base rate moratorium, a three -year continuation of the Choice Gas Program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements. The WPSC order includes a three -year continuation of the Choice Gas Program, as well as various other terms and reporting requirements. All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska. However, Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs. Settlement of Gas Supply Contract On April 29, 2016, we settled for $40 million , a former SourceGas contract that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities in the purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of the net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five -year period. Pro Forma Results (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, 2015: Pro Forma Results December 31, 2016 2015 (in thousands, except per share amounts) Revenue $ 1,651,936 $ 1,763,901 Net income (loss) available for common stock $ 112,878 $ (13,369 ) Earnings (loss) per share, Basic $ 2.17 $ (0.26 ) Earnings (loss) per share, Diluted $ 2.12 $ (0.26 ) 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, 2015 , also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the 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, 2015, or that may be obtained in the future. Seller’s noncontrolling interest One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction, we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. If we choose not to exercise this option during a ninety-day period, the seller may exercise the put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying consolidated balance sheets. |
Property, Plant And Equipment_
Property, Plant And Equipment: | 12 Months Ended |
Dec. 31, 2016 | |
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): 2016 2015 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 $ 1,303,101 41 $ 1,136,847 43 30 63 Electric transmission 354,801 52 280,257 50 40 70 Electric distribution 712,575 48 699,775 47 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 164,761 25 159,496 24 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,801,549 2,542,686 Construction work in progress 74,045 96,501 Total electric plant 2,875,594 2,639,187 Less accumulated depreciation and amortization 578,162 526,954 Electric plant net of accumulated depreciation and amortization (c) $ 2,297,432 $ 2,112,233 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 14 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. (c) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. 2016 2015 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 $ 10,821 35 $ 13 30 17 71 Gas transmission 338,729 48 45,104 60 22 70 Gas distribution 1,303,366 42 692,800 45 33 47 Cushion gas - depreciable (a) 3,539 28 — 0 28 28 Cushion gas - not depreciated (a) 47,055 0 — 0 0 0 Storage 27,686 31 — 0 15 48 General 339,382 19 122,109 22 3 44 Total gas plant in service 2,070,578 860,026 Construction work in progress 28,446 11,854 Total gas plant 2,099,024 871,880 Less accumulated depreciation and amortization 194,585 120,458 Gas plant net of accumulated depreciation and amortization (b) $ 1,904,439 $ 751,422 _____________ (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. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. 2016 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 $ 161,430 $ 1,298 $ 162,728 $ 55,157 $ 107,571 33 2 40 Mining 151,709 4,642 156,351 105,219 51,132 13 2 59 Oil and Gas (a) 1,101,106 — 1,101,106 1,016,226 84,880 25 2 25 _____________ (a) Net Property, Plant and Equipment includes full cost pool net assets of approximately $43 million . 2015 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 $ 156,721 $ 2,182 $ 158,903 $ 51,471 $ 107,432 33 2 40 Mining 154,630 3,649 158,279 97,663 60,616 13 2 59 Oil and Gas 1,132,776 — 1,132,776 925,908 206,868 24 3 25 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,446 $ 11,974 $ 17,420 $ (6,115 ) $ 23,535 8 3 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. 2015 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 376 $ 15,377 $ 15,753 $ (4,770 ) $ 20,523 10 5 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. |
Jointly Owned Facilities_
Jointly Owned Facilities: | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Jointly Owned Facilities | JOINTLY OWNED FACILITIES Utility Plant Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the 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 MAPP 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. We retain responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant. • Colorado Electric owns 50% of the Busch Ranch Wind Farm while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm for the life of the facility. We retain responsibility for operations of the wind farm. Non-Regulated Plants Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income (Loss). Each of the respective owners is responsible for providing its own financing. • 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. We retain responsibility for plant operations. At December 31, 2016 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 113,611 $ 256 $ 55,878 Transmission Tie $ 19,978 $ 13 $ 5,793 Wygen I $ 109,412 $ 957 $ 37,156 Wygen III $ 138,261 $ 1,806 $ 17,635 Busch Ranch Wind Farm $ 18,899 $ — $ 3,102 |
Business Segments Information_
Business Segments Information: | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting Information, Additional Information [Abstract] | |
Business Segments Information | BUSINESS SEGMENTS 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 inter-company eliminations) as of December 31, 2016 2015 Electric (a) (d) $ 2,859,559 $ 2,704,330 Gas (b) (d) 3,307,967 999,778 Power Generation (a) 73,445 60,864 Mining 67,347 76,358 Oil and Gas 96,435 208,956 Corporate (c) 110,691 576,357 Total assets $ 6,515,444 $ 4,626,643 __________________ (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) Includes the assets acquired in the SourceGas acquisition on February 12, 2016. (c) Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million , previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2016 2015 Capital Expenditures Electric Utilities (b) $ 258,739 $ 171,897 Gas Utilities (b) 173,930 99,674 Power Generation 4,719 2,694 Mining 5,709 5,767 Oil and Gas 6,669 168,925 Corporate 17,353 9,864 Total Capital Expenditures 467,119 458,821 Asset Acquisitions Gas Utilities (b) (c) 1,124,238 21,970 Total Capital Expenditures and Asset Acquisitions $ 1,591,357 $ 480,791 _________________ (a) Includes accruals for property, plant and equipment. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. (c) SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2. The 2015 acquisitions represent two acquisitions made by Wyoming Gas. Property, Plant and Equipment as of December 31, 2016 2015 Electric Utilities (a) (b) $ 2,875,594 $ 2,639,187 Gas Utilities (b) (c) 2,099,024 871,880 Power Generation (a) 162,728 158,903 Mining 156,351 158,279 Oil and Gas 1,101,106 1,132,776 Corporate 17,420 15,753 Total property, plant and equipment $ 6,412,223 $ 4,976,778 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility Property, Plant and Equipment of $130 million , previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. (c) Includes Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016. Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ 34,058 $ — $ — $ 1,572,974 Inter-company revenue 12,951 — 83,955 31,213 — 347,500 (475,619 ) — Total revenue 677,281 838,343 91,131 60,280 34,058 347,500 (475,619 ) 1,572,974 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 32,158 373,773 (326,847 ) 555,256 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 13,902 22,538 (23,827 ) 189,043 Impairment of long-lived assets (a) — — — — 106,957 — — 106,957 Operating income (loss) 173,153 162,017 54,391 11,358 (118,959 ) (49,267 ) (10,107 ) 222,586 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (4,864 ) (109,035 ) 115,469 (135,412 ) Interest income 5,946 1,573 1,983 24 — 97,147 (105,244 ) 1,429 Other income (expense), net 3,193 184 2 2,209 110 179,839 (181,034 ) 4,503 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 52,659 24,365 457 (10,475 ) Net income (loss) 85,827 59,726 35,489 10,053 (71,054 ) 143,049 (180,459 ) 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 $ (71,054 ) $ 143,049 $ (180,459 ) $ 72,970 ________________ (a) Oil and Gas includes oil and gas property impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2015 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 668,226 $ 551,300 $ 7,483 $ 34,313 $ 43,283 $ — $ — $ 1,304,605 Inter-company revenue 11,617 — 83,307 30,753 — 227,708 (353,385 ) — Total revenue 679,843 551,300 90,790 65,066 43,283 227,708 (353,385 ) 1,304,605 Fuel, purchased power and cost of natural gas sold 269,409 299,645 — — — 122 (112,289 ) 456,887 Operations and maintenance 160,924 140,723 32,140 41,630 41,593 225,721 (229,786 ) 412,945 Depreciation, depletion and amortization 80,929 32,326 4,329 9,806 29,287 9,273 (10,580 ) 155,370 Impairment of long-lived assets (a) — — — — 249,608 — — 249,608 Operating income (loss) 168,581 78,606 54,321 13,630 (277,205 ) (7,408 ) (730 ) 29,795 Interest expense (55,159 ) (17,912 ) (4,218 ) (433 ) (2,726 ) (57,839 ) 54,568 (83,719 ) Interest income 4,114 601 1,015 34 217 48,582 (52,942 ) 1,621 Other income (expense), net 1,216 315 71 2,247 (337 ) 70,889 (71,964 ) 2,437 Impairment of equity investments (a) — — — — (4,405 ) — — (4,405 ) Income tax benefit (expense) (41,173 ) (22,304 ) (18,539 ) (3,608 ) 104,498 2,926 360 22,160 Net income (loss) 77,579 39,306 32,650 11,870 (179,958 ) 57,150 (70,708 ) (32,111 ) Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 77,579 $ 39,306 $ 32,650 $ 11,870 $ (179,958 ) $ 57,150 $ (70,708 ) $ (32,111 ) ________________ (a) Oil and Gas includes ceiling test and equity investment impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2014 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 643,446 $ 657,523 $ 6,401 $ 31,086 $ 55,114 $ — $ — $ 1,393,570 Inter-company revenue 14,110 — 81,157 32,272 — 222,460 (349,999 ) — Total revenue 657,556 657,523 87,558 63,358 55,114 222,460 (349,999 ) 1,393,570 Fuel, purchased power and cost of natural gas sold 291,644 403,781 — — — 116 (113,759 ) 581,782 Operations and maintenance 156,252 142,024 33,126 41,172 42,659 213,415 (225,473 ) 403,175 Depreciation, depletion and amortization 77,011 28,912 4,540 10,276 24,246 7,690 (7,930 ) 144,745 Operating income (loss) 132,649 82,806 49,892 11,910 (11,791 ) 1,239 (2,837 ) 263,868 Interest expense (51,640 ) (17,487 ) (4,351 ) (493 ) (2,603 ) (50,299 ) 55,913 (70,960 ) Interest income 4,590 466 682 59 918 48,969 (53,759 ) 1,925 Other income (expense), net 1,074 124 (6 ) 2,275 183 61,605 (62,574 ) 2,681 Income tax benefit (expense) (29,403 ) (21,758 ) (17,701 ) (3,299 ) 4,768 24 744 (66,625 ) Net income (loss) 57,270 44,151 28,516 10,452 (8,525 ) 61,538 (62,513 ) 130,889 Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 57,270 $ 44,151 $ 28,516 $ 10,452 $ (8,525 ) $ 61,538 $ (62,513 ) $ 130,889 |
Long-Term Debt_
Long-Term Debt: | 12 Months Ended |
Dec. 31, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Long-term Debt | LONG-TERM DEBT Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Due Date December 31, 2016 December 31, 2016 December 31, 2015 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 Corporate term loan due 2017 (a) — 300,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% 250,000 — Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 — Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 — Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 — Corporate term loan due 2019 (a) August 9, 2019 1.74% 400,000 — Corporate term loan due 2021 June 7, 2021 2.32% 24,406 — Total Corporate Debt 2,698,406 1,324,000 Less unamortized debt discount (4,413 ) (1,890 ) Total Corporate Debt, Net 2,693,993 1,322,110 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 0.72% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 0.72% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 0.88% 2,855 2,855 Total Electric Utilities Debt 544,855 544,855 Less unamortized debt discount (94 ) (99 ) Total Electric Utilities Debt 544,761 544,756 Total long-term debt 3,238,754 1,866,866 Less current maturities 5,743 — Less deferred financing costs (d) 21,822 13,184 Long-term debt, net of current maturities and deferred financing costs $ 3,211,189 $ 1,853,682 _______________ (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, 2016 and December 31, 2015 , respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2017 $ 5,743 2018 $ 5,743 2019 $ 655,742 2020 $ 205,742 2021 $ 8,436 Thereafter $ 2,361,855 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2016 . 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. Assumption of Long-Term Debt At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following: • $325 million , 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017. • $95 million , 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019. • $340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875% . The $760 million in long-term debt assumed in the SourceGas Acquisition was repaid in August 2016. Debt Transactions On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10 -year senior notes due January 15, 2027 and $300 million of 4.20% 30 -year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following: • Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition; • Repay the $95 million , 3.98% senior secured notes assumed in the SourceGas Acquisition; • Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition; • Pay down $100 million of the $500 million three -year unsecured term loan discussed below; • Payment of $29 million for the settlement of $400 million notional interest rate swap; and • Remainder was used for general corporate purposes. On August 9, 2016, we entered into a $500 million , three -year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 1, on June 7, 2016, we entered into a 2.32% , $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million , the first of which was paid on June 30, 2016. On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95% , ten -year senior notes due 2026, and $250 million of 2.50% , three -year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note. 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, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 Senior unsecured notes due 2023 2,921 494 494 653 Senior unsecured notes due 2019 763 643 — — Senior unsecured notes due 2020 592 167 167 167 Senior unsecured notes due 2026 2,318 262 — — Senior unsecured notes due 2027 3,281 121 — — Senior unsecured notes due 2046 3,193 37 — — Corporate term loan due 2019 287 144 — — Bridge Term Loan — 843 4,213 — RSNs due 2028 1,449 122 10 — First mortgage bonds due 2044 (South Dakota Electric) 663 24 24 6 First mortgage bonds due 2044 (Wyoming Electric) 613 23 22 6 First mortgage bonds due 2032 518 33 33 33 First mortgage bonds due 2039 1,734 76 76 76 First mortgage bonds due 2037 643 31 31 31 Other 506 304 43 53 Total $ 21,822 $ 3,861 $ 5,617 $ 1,641 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, 2016 , 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, 2016 : • 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, 2016 , the restricted net assets at our Electric and Gas Utilities were approximately $257 million . |
Notes Payable_
Notes Payable: | 12 Months Ended |
Dec. 31, 2016 | |
Notes Payable [Abstract] | |
Notes Payable | NOTES PAYABLE Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2016 , 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, 2016 December 31, 2015 Revolving Credit Facility $ 96,600 $ 76,800 Revolving Credit Facility On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one -year extension options (subject to consent from the lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility 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 most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250% , 1.250% , and 1.250% , respectively, at December 31, 2016 . A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility. On December 22, 2016, we implemented 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. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of December 31, 2016. As of December 31, 2016 and 2015 , we had outstanding letters of credit totaling approximately $36 million and approximately $33 million , respectively. Deferred financing costs on the facility of $5.4 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income (Loss). The deferred financing costs on the new facility are being amortized as follows (in thousands): Deferred Financing Costs Remaining on Balance Sheet as of Amortization Expense for the years ended December 31, December 31, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 Debt Covenants On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 for the quarter ending December 31, 2016 and subsequently for future quarters beginning March 31, 2017, maintain the 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, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: At December 31, 2016 Covenant Requirement at December 31, 2016 Consolidated Indebtedness to Capitalization Ratio 62 % Less than 70 % |
Asset Retirement Obligations_
Asset Retirement Obligations: | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, 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 regulated utilities segments. 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 ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b)(c) December 31, 2016 Electric Utilities $ 4,462 $ — $ — $ 191 $ — $ 8 $ 4,661 Gas Utilities 136 — — 791 22,412 6,436 29,775 Mining 18,633 — (105 ) 822 — (6,910 ) 12,440 Oil and Gas 21,504 3 (2,049 ) 1,382 — 1,923 22,763 Total $ 44,735 $ 3 $ (2,154 ) $ 3,186 $ 22,412 $ 1,457 $ 69,639 December 31, 2014 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired Revisions to Prior Estimates (c) December 31, 2015 Electric Utilities $ 7,012 $ — $ (2,733 ) $ 183 $ — $ — $ 4,462 Gas Utilities 291 — (168 ) 13 — — 136 Mining 19,138 — — 993 — (1,498 ) 18,633 Oil and Gas 20,945 828 (1,792 ) 1,371 — 152 21,504 Total $ 47,386 $ 828 $ (4,693 ) $ 2,560 $ — $ (1,346 ) $ 44,735 _____________________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. The 2015 Mining Revision to Prior Estimates reflects a change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions. 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 value for the cost of these obligations cannot be measured at this time. |
Risk Management Activities_
Risk Management Activities: | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management Activities | RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal 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 or rate. We are exposed to the following market risks, including, but not limited to: • Commodity price risk associated with our natural long position of crude oil and natural gas reserves and production, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets; and • Interest rate risk associated with our variable rate debt . Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based 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. As of December 31, 2016 , our credit exposure included a $1.1 million exposure to a non-investment grade rural electric cooperative. The remainder of our credit exposure 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 . Oil and Gas We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions from these activities, result in commodity price risk and variability to our cash flows. To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. Futures contracts provide the requirement to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the obligation to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment based on the difference between the fixed price and the settled commodity market price on the settlement date. We elect hedge accounting on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly. The derivatives were marked to fair value and recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income (Loss). The contract or notional amounts and terms of our crude oil futures and options and natural gas futures held at our Oil and Gas segment are comprised of short positions. A short position is a contract to sell the commodity while a long position is a contract to purchase the commodity. We had the following short positions as of: December 31, 2016 December 31, 2015 Crude oil futures and swaps (b) Crude oil options Natural gas futures and swaps (b) Crude oil futures and swaps (b) Natural gas futures and swaps (b) Notional (a) 108,000 36,000 2,700,000 198,000 4,392,500 Maximum terms in months (c) 24 12 24 24 24 ________________________ (a) Crude in Bbls, gas in MMBtus. (b) These financial instruments were designated as cash flow hedges upon inception. (c) Refers to the maximum forward period hedged. Based on December 31, 2016 market prices, a $0.9 million loss would be reclassified from AOCI during 2017 . Estimated and actual realized gains or losses will change during future periods as market prices fluctuate. Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, 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), or the Consolidated Statements of Comprehensive 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 2017 through April 2019. 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, 2016 December 31, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 14,770,000 48 20,580,000 60 Natural gas options purchased, net (b) 3,020,000 5 2,620,000 3 Natural gas basis swaps purchased 12,250,000 48 18,150,000 60 Natural gas over-the-counter swaps, net (c) 4,622,302 28 — 0 Natural gas physical commitments, net (d) 21,504,378 10 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions. (c) As of December 31, 2016 , 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (d) Volumes exclude contracts that qualify for normal purchase, normal sales exception. Financing Activities In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to fix the Treasury yield component associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten -year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten -year life of the $400 million unsecured note issued on August 19, 2016. The ineffective portion of $1.0 million , related to the timing of the debt issuance, was recognized in earnings as a component of interest expense. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2016 December 31, 2015 Interest Rate Swaps (a) Interest Rate Swaps (a) Interest Rate Swaps (b) Notional $ 50,000 $ 75,000 $ 250,000 Weighted average fixed interest rate 4.94 % 4.97 % 2.29 % Maximum terms in months 1 13 16 Derivative assets, non-current $ — $ — $ 3,441 Derivative liabilities, current $ 90 $ 2,835 $ — Derivative liabilities, non-current $ — $ 156 $ — ___________________ (a) The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. (b) These swaps were settled on August 19, 2016. Based on December 31, 2016 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $2.9 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. This total includes the $28 million loss currently deferred in AOCI. Estimated and realized gains or losses will change during future periods as market interest rates change. 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, 2016 and 2015 (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, 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 Revenue 11,019 — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) — Total impact from cash flow hedges $ 7,106 $ (953 ) December 31, 2015 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 $ (3,647 ) $ — Commodity derivatives Revenue 14,460 — Total $ 10,813 $ — December 31, 2014 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 $ (3,669 ) $ — Commodity derivatives Revenue (1,995 ) — Total $ (5,664 ) $ — 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, 2016 , 2015 and 2014 . 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, 2016 December 31, 2015 December 31, 2014 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ (31,222 ) $ 2,888 $ (536 ) Forward commodity contracts (573 ) 9,782 14,681 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 3,899 3,647 3,669 Forward commodity contracts (11,005 ) (14,460 ) 1,995 Total other comprehensive income (loss) from hedging $ (38,901 ) $ 1,857 $ 19,809 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, 2016 , 2015 and 2014 (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. 2016 2015 2014 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 Revenue $ (50 ) $ — $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold 940 — — $ 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 $8.8 million and $24 million at December 31, 2016 and 2015 , respectively. |
Fair Value Measurements_
Fair Value Measurements: | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 or 2015 . 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 . 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, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas $ — $ 2,886 $ — $ (2,733 ) $ 153 Commodity derivatives - Utilities — 7,469 — (3,262 ) 4,207 Interest rate swaps — — — — — Total $ — $ 10,355 $ — $ (5,995 ) $ 4,360 Liabilities: Commodity derivatives - Oil and Gas $ — $ 1,586 $ — $ — $ 1,586 Commodity derivatives - Utilities — 12,201 — (11,144 ) 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 13,877 $ — $ (11,144 ) $ 2,733 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas $ — $ 10,644 $ — $ (10,644 ) $ — Commodity derivatives - Utilities — 2,293 — (2,293 ) — Interest rate swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives - Oil and Gas $ — $ 556 $ — $ (556 ) $ — Commodity derivatives - Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 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): 2016 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets - current $ 1,161 $ — $ 9,981 $ — Commodity derivatives Derivative assets - non-current 124 — 663 — Interest rate swaps Derivative assets - non-current — — 3,441 — Commodity derivatives Derivative liabilities - current — 1,090 — 465 Commodity derivatives Derivative liabilities - non-current — 238 — 91 Interest rate swaps Derivative liabilities - current — 90 — 2,835 Interest rate swaps Derivative liabilities - non-current — — — 156 Total derivatives designated as hedges $ 1,285 $ 1,418 $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ 2,977 $ — $ — $ — Commodity derivatives Derivative assets - non-current 98 — — — Commodity derivatives Derivative liabilities - current — 1,279 — 9,586 Commodity derivatives Derivative liabilities - non-current — 36 — 12,706 Interest rate swaps Derivative liabilities - current — — — — Interest rate swaps Derivative liabilities - non-current — — — — Total derivatives not designated as hedges $ 3,075 $ 1,315 $ — $ 22,292 Derivatives Offsetting It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting for 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, 2016 and December 31, 2015 , 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, 2016 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 Subject to master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 2,886 $ (2,733 ) $ 153 Utilities 4,269 (3,262 ) 1,007 Interest Rate Swaps — — — Total derivative assets subject to a master netting agreement or similar arrangement 7,155 (5,995 ) 1,160 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities 3,200 — 3,200 Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement 3,200 — 3,200 Total derivative assets $ 10,355 $ (5,995 ) $ 4,360 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 1,586 $ — $ 1,586 Utilities 11,144 (11,144 ) — Interest Rate Swaps — — — Total derivative liabilities subject to a master netting agreement or similar arrangement 12,730 (11,144 ) 1,586 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities 1,057 — 1,057 Interest Rate Swaps 90 — 90 Total derivative liabilities not subject to a master netting agreement or similar arrangement 1,147 — 1,147 Total derivative liabilities $ 13,877 $ (11,144 ) $ 2,733 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2015 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 Subject to master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 10,644 $ (10,644 ) $ — Utilities 2,293 (2,293 ) — Interest rate swaps 3,441 — 3,441 Total derivative assets subject to a master netting agreement or similar arrangement 16,378 (12,937 ) 3,441 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities — — — Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement — — — Total derivative assets $ 16,378 $ (12,937 ) $ 3,441 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 556 $ (556 ) $ — Utilities 24,585 (24,585 ) — Interest Rate Swaps 2,991 — 2,991 Total derivative liabilities subject to a master netting agreement or similar arrangement 28,132 (25,141 ) 2,991 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities — — — Interest Rate Swaps — — — Total derivative liabilities not subject to a master netting agreement or similar arrangement — — — Total derivative liabilities $ 28,132 $ (25,141 ) $ 2,991 |
Fair Value Of Financial Instrum
Fair Value Of Financial Instruments: | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Instruments | FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 13,580 $ 13,580 $ 440,861 $ 440,861 Restricted cash and equivalents (a) $ 2,274 $ 2,274 $ 1,697 $ 1,697 Notes payable (b) $ 96,600 $ 96,600 $ 76,800 $ 76,800 Long-term debt, including current maturities (c) $ 3,216,932 $ 3,351,305 $ 1,853,682 $ 1,992,274 _______________ (a) Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Cash and Cash Equivalents Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds, and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements 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, 2016 | |
Stockholders' Equity Note [Abstract] | |
Stock | EQUITY Equity Units On November 23, 2015, we issued 5.98 million equity units for total gross proceeds of $299 million . Each Equity Unit has a stated amount of $50 and consists 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. The RSNs, a debt instrument, and the forward purchase contracts, an equity instrument, are deemed to be separate instruments as the investor may trade the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately. The forward purchase contracts obligate the holders to purchase from the Company on the settlement date, which shall be no later than November 1, 2018, for a price of $50 in cash, the following number of shares of our common stock, subject to anti-dilution adjustments: • if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938 , 1.0572 shares of the Company’s common stock per Equity Unit; • if the AMV is less than $47.2938 but greater than $40.25 , a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50 ; and • if the AMV is less than or equal to $40.25 , 1.2422 shares of the Company’s common stock. The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing, the interest rate on the RSNs will not be reset, and the holders of the RSNs will have the right to put the RSNs to the Company at a price equal to 100% of the principal amount, and the proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts. The Company will also pay the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million , is recorded as a reduction of shareholders’ equity. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2016, the forward purchase contracts were dilutive and therefore included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders. Selected information about our equity units is presented below (in thousands except for percentages) : Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability as of December 31, 2016 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 23,335 At-the-Market Equity Offering Program On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million . The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended December 31, 2016, we issued 218,647 common shares for $13 million , net of $0.1 million in commissions under the ATM equity offering program. Through December 31, 2016, we have sold and 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. As of December 31, 2016, there were no shares sold that were not settled. Common Stock Offering On November 23, 2015, we issued 6.325 million shares of Common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million . The proceeds from the offering were used to partially fund the purchase of SourceGas, which closed on February 12, 2016. 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 1,115,557 shares available to grant at December 31, 2016 . 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, 2016 , total unrecognized compensation expense related to non-vested stock awards was approximately $13.5 million and is expected to be recognized over a weighted-average period of 2.0 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): 2016 2015 2014 Stock-based compensation expense $ 10,885 $ 4,076 $ 9,329 Stock Options The Company has not issued any stock options since 2014 and has 119,415 stock options outstanding at December 31, 2016. The amount of stock options granted during the last three years, related exercise activity and the number of stock options outstanding at December 31, 2016 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, 2016 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 202 $ 48.96 Granted 195 53.55 Vested (88 ) 48.00 Forfeited (14 ) 51.89 Balance at end of period 295 $ 52.15 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) 2016 $ 53.55 $ 4,602 2015 $ 50.01 $ 6,009 2014 $ 54.34 $ 6,114 As of December 31, 2016 , there was $10.3 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 $2.3 million at December 31, 2016 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, 2014 January 1, 2014 - December 31, 2016 44 0% 200% January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% January 1, 2016 January 1, 2016 - December 31, 2018 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, 2016 (in thousands) (in thousands) Performance Shares balance at beginning of period 74 $ 47.21 74 Granted 27 47.76 27 Forfeited — — — Vested (30 ) 35.86 (30 ) Performance Shares balance at end of period 71 $ 52.29 71 $ 48.05 _____________________ (a) The grant date fair values for the performance shares granted in 2016 , 2015 and 2014 were determined by Monte Carlo simulation using a blended volatility of 24% , 21% and 23% , 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, 2016 $ 47.76 December 31, 2015 $ 54.92 December 31, 2014 $ 55.18 Performance plan payouts have been as follows (dollars and shares in thousands): Performance Period Year of Payment Shares Issued Cash Paid Total Intrinsic Value January 1, 2013 to December 31, 2015 2016 — $ — $ — January 1, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314 January 1, 2011 to December 31, 2013 2014 59 $ 3,011 $ 6,020 On January 24, 2017 , the Compensation Committee of our Board of Directors determined that the Company’s performance criteria for the January 1, 2014 through December 31, 2016 performance period was not met. As a result, there will be no payout for this period. As of December 31, 2016 , there was $3.1 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 are currently issuing new shares. A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands): 2016 2015 Shares Issued 51 66 Weighted Average Price $ 58.24 $ 44.79 Unissued Shares Available 356 408 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. ASC 810 requires the accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Net income available for common stock for the year ended December 31, 2016, was reduced by $9.6 million 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: 2016 2015 (in thousands) Assets Current assets $ 12,627 $ — Property, plant and equipment of variable interest entities, net $ 218,798 $ — Liabilities Current liabilities $ 4,342 $ — |
Impairment Of Assets_
Impairment Of Assets: | 12 Months Ended |
Dec. 31, 2016 | |
Asset Impairment Charges [Abstract] | |
Impairment of Assets | IMPAIRMENT OF ASSETS Long-lived assets Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. As a result of continued low commodity prices throughout 2016, we have recorded non-cash ceiling test impairments of oil and gas assets included in the Oil and Gas segment 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. In 2015, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment totaling approximately $250 million for the year ended December 31, 2015. 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 $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead. During the second quarter of 2016, we advanced our Oil and Gas strategy, identifying certain non-core assets which may be sold as they are not expected to be utilized in the Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million , in addition to the impairments noted above. The remaining book value of these depreciable assets is approximately $23 million as of December 31, 2016. Equity investments in unconsolidated subsidiaries Our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, due to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements . We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million , the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system. |
Operating Leases_
Operating Leases: | 12 Months Ended |
Dec. 31, 2016 | |
Leases, Operating [Abstract] | |
Operating Leases | OPERATING LEASES We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands): 2016 2015 2014 Rent expense $ 9,568 $ 7,177 $ 6,932 The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2017 $ 6,739 2018 $ 5,564 2019 $ 4,441 2020 $ 2,639 2021 $ 1,652 Thereafter $ 6,245 |
Income Taxes_
Income Taxes: | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2016 2015 2014 Current: Federal $ (23,820 ) $ 2,549 $ (2,319 ) State (1,922 ) 1,319 (1,288 ) (25,742 ) 3,868 (3,607 ) Deferred: Federal 36,012 (23,592 ) 64,780 State 257 (2,323 ) 5,658 Tax credit amortization (52 ) (113 ) (206 ) 36,217 (26,028 ) 70,232 $ 10,475 $ (22,160 ) $ 66,625 The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2016 2015 Deferred tax assets: Regulatory liabilities $ 58,200 $ 43,586 Employee benefits 29,638 26,400 Federal net operating loss 252,780 217,922 Other deferred tax assets (a) 83,485 85,907 Less: Valuation allowance (9,263 ) (4,304 ) Total deferred tax assets 414,840 369,511 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (b) (820,111 ) (711,293 ) Regulatory assets (49,471 ) (29,092 ) State deferred tax liability (47,987 ) (35,065 ) Deferred costs (18,551 ) (26,121 ) Other deferred tax liabilities (14,326 ) (18,519 ) Total deferred tax liabilities (950,446 ) (820,090 ) Net deferred tax liability $ (535,606 ) $ (450,579 ) _______________ (a) Other deferred tax assets consist primarily of state tax credits, state net operating loss, alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million , previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration. The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2016 2015 2014 Federal statutory rate (e) 35.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 0.2 1.0 1.1 Amortization of excess deferred income taxes and investment tax credits (0.1 ) 0.2 (0.1 ) Percentage depletion (a) (8.2 ) 3.5 (1.0 ) Non-controlling interest (d) (3.6 ) — — Equity AFUDC (1.1 ) 0.3 (0.1 ) Tax credits (1.5 ) 0.5 (0.1 ) Transaction costs 1.1 — — Accounting for uncertain tax positions adjustment (b) (6.0 ) (3.5 ) (0.1 ) Flow-through adjustments (c) (5.1 ) 3.8 (0.9 ) Other tax differences 0.6 — (0.1 ) 11.3 % 40.8 % 33.7 % _________________________ (a) The tax benefit includes additional percentage depletion deductions that were claimed with respect to the oil and gas properties involving prior tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (b) The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. (c) The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. 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. (d) Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded. (e) The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net loss. At December 31, 2016 , we have federal and gross state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 721,075 2019 to 2036 State Net Operating Loss Carryforward $ 616,524 2017 to 2036 As of December 31, 2016 , we had a $0.9 million valuation allowance against the state NOL carryforwards. Our 2016 analysis of the ability to utilize such NOLs resulted in a slight increase of the valuation allowance of approximately $0.1 million , which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2016. Such a 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, 2014 $ 37,631 Additions for prior year tax positions 1,253 Reductions for prior year tax positions (6,692 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2014 32,192 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 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 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million . As a result of an agreement in principle that was reached with IRS Appeals in the first quarter of 2016, we recognized no interest expense for the year ended December 31, 2016, and approximately $1.8 million and $1.6 million for the years ended December 31, 2015 and 2014 , respectively. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2016, and approximately $13.3 million accrued at December 31, 2015. We file income tax returns with the IRS and various state jurisdictions. We received a 30-day Letter along with a Revenue Agent’s Report from the IRS in regards to the audit of the 2007 to 2009 tax years. A protest was timely filed with the IRS in August 2014 related to the like-kind exchange transaction described below and research and development (“R&D”) credits and deductions claimed with respect to certain costs and projects. A settlement in principle was reached with IRS Appeals in the first quarter of 2016. We are also currently under examination by the IRS for the 2010 to 2012 tax years. We received a 30-day letter along with Revenue Agent’s Report from the IRS in regard to the audit of the 2010 to 2012 tax years. A protest was timely filed with IRS Appeals in the second quarter of 2016 related to R&D credits and deductions claimed with respect to certain costs and projects. We have 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. 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, 2016, 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, 2017. Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2016 , we had foreign tax credit carryforwards of approximately $2.3 million , which expire in 2017 . We had a $1.7 million and $0.5 million valuation allowance against the foreign tax credit carryforwards as of December 31, 2016 and 2015 respectively. Approximately $1.8 million of foreign tax credits was previously reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization. Subsequent to the settlement agreement in principle that was reached with IRS Appeals in the first quarter of 2016, it has been determined to be more beneficial to deduct the $1.8 million of foreign tax credits. In determining the valuation allowance amount, we compared the tax benefit associated with either deducting foreign taxes or claiming them as credits. The tax benefit of being able to deduct such foreign tax credits is approximately $0.6 million resulting in an increase to the valuation allowance of approximately $1.2 million . State tax credits have been generated and are available to offset future state income taxes. At December 31, 2016 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 19,765 2023 to 2036 Research and development $ 167 No expiration As of December 31, 2016 , we had a $6.6 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.6 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.7 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 2016. 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, 2016 | |
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, 2016 December 31, 2015 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (3,899 ) $ (3,647 ) Commodity contracts Revenue 11,019 14,460 Commodity contracts Fuel, purchased power and cost of natural gas sold (14 ) — 7,106 10,813 Income tax Income tax benefit (expense) (2,702 ) (4,271 ) Total reclassification adjustments related to cash flow hedges, net of tax $ 4,404 $ 6,542 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 221 $ 238 Actuarial gain (loss) Operations and maintenance (1,978 ) (2,822 ) (1,757 ) (2,584 ) Income tax Income tax benefit (expense) 533 884 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,224 ) $ (1,700 ) Total reclassifications $ 3,180 $ 4,842 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, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (20,302 ) (361 ) (1,985 ) (22,648 ) Amounts reclassified from AOCI 2,534 (6,938 ) 1,224 (3,180 ) As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2014 $ (4,930 ) $ 10,023 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss) before reclassifications 2,290 5,884 2,657 10,831 Amounts reclassified from AOCI 2,299 (8,841 ) 1,700 (4,842 ) As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash flow Information: | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Years ended December 31, 2016 2015 2014 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 29,082 $ 40,250 $ 52,584 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 8,577 $ (518 ) $ (5,634 ) Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (112,925 ) $ (77,810 ) $ (69,239 ) Income taxes, net $ (1,156 ) $ (1,202 ) $ (413 ) |
Employee Benefit Plans_
Employee Benefit Plans: | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS On February 12, 2016, as disclosed in Note 2 , we completed the acquisition of SourceGas, adding an additional defined benefit pension plan, two additional defined benefit healthcare postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement, among other factors. In accordance with accounting standards, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a Regulatory asset and will be amortized over the average remaining service life of the plans. Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Postretirement benefit obligation $ 22,187 $ 11,751 Defined Contribution Plans We sponsor 401(k) retirement savings plans (the 401(k) Plans). Participants in the 401(k) Plans may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plans provide employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plans provide a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Retirement Contribution based on the participant’s age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Defined Benefit Pension Plans (Pension Plans) During 2016 we maintained three defined benefit pension plans, BHC Pension Plan, Black Hills Utility Holding, Inc. Pension Plan and SourceGas Retirement Plan that as of December 31, 2016 were merged into one single plan, the Black Hills Retirement Plan. The Pension Plans cover certain eligible employees of the Company. The benefits for the Pension Plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. All three Pension Plans have been closed to new employees and certain employees who did not meet age and service based criteria. Black Hills Retirement Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 will no longer represent an undivided interest in the Master Trust. Our Board of Directors has approved the Plans’ 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 Plans’ 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 Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2016, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40% to 50% equity securities and 50% to 60% fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 30% to 40% equity securities and 60% to 70% fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs. The expected long-term rate of return for investments was 6.75% for the BHC Pension Plan and Black Hills Utility Holding, Inc. Plan 2016 and 2015 plan years and 7.5% for the SourceGas Retirement Plan 2016 plan year. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows: 2016 2015 Equity 28% 26% Real estate 5 5 Fixed income 57 59 Cash 2 1 Hedge funds 8 9 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 With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via VEBAs and a Grantor Trust. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan. 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 provides 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 Plans are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands): 2016 2015 Defined Contribution Plan Company Retirement Contribution $ 9,632 $ 5,564 Matching contributions $ 9,645 $ 9,616 2016 2015 Defined Benefit Plans Defined Benefit Pension Plans $ 14,200 $ 10,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 4,965 $ 3,771 Supplemental Non-Qualified Defined Benefit Plans $ 1,565 $ 1,564 While we do not have required contributions, we expect to make approximately $10 million in contributions to our Defined Benefit Pension Plans in 2017 . 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): Defined Benefit Pension Plans December 31, 2016 Level 1 Level 2 Level 3 NAV (a) Total AXA Equitable General Fixed Income $ — $ 1,325 $ — — $ 1,325 Common Collective Trust - Cash and Cash Equivalents — 5,307 — — 5,307 Common Collective Trust - Equity — 101,020 — — 101,020 Common Collective Trust - Fixed Income — 209,815 — — 209,815 Common Collective Trust - Real Estate — 2,349 — 15,563 17,912 Hedge Funds — — — 29,316 29,316 Total investments measured at fair value $ — $ 319,816 $ — $ 44,879 $ 364,695 Defined Benefit Pension Plans December 31, 2015 Level 1 Level 2 Level 3 NAV (a) Total AXA Equitable General Fixed Income $ — $ 1,072 $ — $ — $ 1,072 Common Collective Trust - Cash and Cash Equivalents — 1,556 — — 1,556 Common Collective Trust - Equity — 74,885 — — 74,885 Common Collective Trust - Fixed Income — 172,016 — — 172,016 Common Collective Trust - Real Estate — 2,204 — 11,143 13,347 Hedge Funds — — — 25,746 25,746 Total investments measured at fair value $ — $ 251,733 $ — $ 36,889 $ 288,622 _____________ (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. Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2016 Level 1 Level 2 Level 3 Total Cash and Cash Equivalents $ 111 $ — $ — $ 111 Equity Securities 1,154 — — 1,154 Registered Investment Company Trust - Money Market Mutual Fund — 4,732 — 4,732 Intermediate-term Bond — 2,473 — 2,473 Total investments measured at fair value $ 1,265 $ 7,205 $ — $ 8,470 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2015 Level 1 Level 2 Level 3 Total Registered Investment Company Trust - Money Market Mutual Fund $ — $ 4,681 $ — $ 4,681 Total investments measured at fair value $ — $ 4,681 $ — $ 4,681 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 (EFTs) for diversification into the other sectors of the economy. EFTs 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 place 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 at which loans with similar characteristics have. 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 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. Certain of the funds’ assets contain participant withdrawal policy. Hedge Funds: Hedge funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Projected benefit obligation at beginning of year $ 356,575 $ 377,772 $ 40,219 $ 41,211 $ 48,077 $ 49,042 Transfer from SourceGas Acquisition 75,254 — — — 15,091 — Service cost 7,619 6,093 2,099 1,300 1,757 1,808 Interest cost 15,743 15,522 1,257 1,455 1,942 1,801 Actuarial (gain) loss (a) 7,001 (28,229 ) 2,049 (2,072 ) 2,808 (1,206 ) Amendments — — — — 2,203 — Benefits paid (22,013 ) (14,583 ) (1,755 ) (1,675 ) (4,965 ) (3,771 ) Medicare Part D accrued — — — — — (178 ) Plan participants’ contributions — — — — 1,110 581 Projected benefit obligation at end of year $ 440,179 $ 356,575 $ 43,869 $ 40,219 $ 68,023 $ 48,077 ____________________ (a) Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates. Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans (a) 2016 2015 2016 2015 2016 2015 Beginning fair value of plan assets $ 288,622 $ 299,533 $ — $ — $ 4,681 $ 4,705 Transfer from SourceGas Acquisition 53,067 — — — 3,340 — Investment income (loss) 30,819 (6,528 ) — — 256 (9 ) Employer contributions 14,200 10,200 — — 4,048 3,175 Retiree contributions — — — — 1,110 581 Benefits paid (22,013 ) (14,583 ) — — (4,965 ) (3,771 ) Plan administrative expenses — — — — — — Ending fair value of plan assets $ 364,695 $ 288,622 $ — $ — $ 8,470 $ 4,681 ____________________ (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 Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Regulatory assets $ 66,640 $ 68,915 $ — $ — $ 11,401 $ 6,464 Current liabilities $ — $ — $ 1,583 $ 1,568 $ 4,360 $ 3,543 Non-current assets $ — $ — $ — $ — $ 21 $ 23 Non-current liabilities $ 75,484 $ 67,953 $ 42,286 $ 38,651 $ 55,214 $ 39,855 Regulatory liabilities $ 5,195 $ — $ — $ — $ 3,419 $ 3,209 Accumulated Benefit Obligation (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Accumulated Benefit Obligation (a) $ 416,786 $ 334,923 $ 32,090 $ 30,558 $ 68,023 $ 48,077 ____________________ (a) The Defined Benefit Pension Plans Accumulated Benefit Obligation for 2016 represents the obligation for the merged Black Hills Retirement Plan. The 2015 obligation represents the BHC Pension Plan and Black Hills Utility Holding, Inc. Pension Plan and has been combined for presentation purposes to conform to the 2016 merged plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2016 represents that obligation for the five postretirement plans maintained by BHC. The 2015 obligation represents the three postretirement plans maintained by BHC. Components of Net Periodic Expense (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2014 2016 2015 2014 2016 2015 2014 Service cost $ 7,619 $ 6,093 $ 5,448 $ 1,335 $ 1,380 $ 1,498 $ 1,757 $ 1,808 $ 1,700 Interest cost 15,743 15,522 15,852 1,257 1,455 1,447 1,942 1,801 1,919 Expected return on assets (23,062 ) (19,470 ) (18,065 ) — — — (279 ) (131 ) (85 ) Net amortization of prior service cost 58 58 62 2 2 2 (428 ) (428 ) (428 ) Recognized net actuarial loss (gain) 7,173 11,037 4,806 829 1,081 498 335 408 160 Settlement Expense (a) 10 — — — — — — — — Net periodic expense $ 7,541 $ 13,240 $ 8,103 $ 3,423 $ 3,918 $ 3,445 $ 3,327 $ 3,458 $ 3,266 ____________________ (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. 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 Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Net (gain) loss $ 8,472 $ 8,777 $ 7,132 $ 6,339 $ 1,595 $ 1,704 Prior service cost (gain) 31 41 5 6 (694 ) (1,087 ) Total AOCI $ 8,503 $ 8,818 $ 7,137 $ 6,345 $ 901 $ 617 The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2017 are as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 2,604 $ 572 $ 325 Prior service cost (credit) 38 1 (368 ) Total net periodic benefit cost expected to be recognized during calendar year 2017 $ 2,642 $ 573 $ (43 ) Assumptions Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.27 % 4.58 % 4.19 % 4.02 % 4.28 % 4.19 % 3.96 % 4.17 % 3.82 % Rate of increase in compensation levels 3.47 % 3.51 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plans 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: 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate (a) 4.50 % 4.19 % 5.04 % 4.28 % 4.19 % 5.03 % 4.18 % 3.82 % 4.46 % Expected long-term rate of return on assets (b) 6.87 % 6.75 % 6.75 % N/A N/A N/A 3.83 % 3.00 % 2.00 % Rate of increase in compensation levels 3.42 % 3.76 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Retirement Plan is 4.27% for the calculation of the 2017 net periodic pension costs. (b) The expected rate of return on plan assets is 6.75% for the calculation of the 2017 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: 2016 (a) 2015 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.35% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2024 2024 Post-65 for next year - All Plans 5.10% 5.20% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2023 2023 _____________________________ (a) The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas. We do not pre-fund our supplemental plans or three of the five healthcare plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands): Change in Assumed Trend Rate Impact on December 31, 2016 Accumulated Postretirement Benefit Obligation Impact on 2017 Service and Interest Cost Increase 1% $ 2,569 $ 156 Decrease 1% $ (2,191 ) $ (131 ) 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. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. 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 2017 $ 21,355 $ 1,583 $ 5,504 2018 $ 21,566 $ 1,809 $ 5,779 2019 $ 23,010 $ 1,921 $ 5,886 2020 $ 27,028 $ 1,634 $ 5,983 2021 $ 27,614 $ 1,836 $ 5,931 2022-2026 $ 149,893 $ 11,009 $ 27,585 |
Commitments And Contingencies_
Commitments And Contingencies: | 12 Months Ended |
Dec. 31, 2016 | |
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 has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023 . The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. • 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 inter-company 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 inter-company agreement, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to South Dakota Electric. • Colorado Electric’s REPA with AltaGas expiring October 16, 2037 , provides up to 14.5 MW of wind energy from the Busch Ranch Wind Farm in which Colorado Electric owns a 50% undivided ownership interest. Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2016 2015 2014 PPA with PacifiCorp $ 12,221 $ 13,990 $ 13,943 Transmission services agreement with PacifiCorp $ 1,428 $ 1,213 $ 1,227 PPA with Happy Jack $ 3,836 $ 3,155 $ 3,919 PPA with Silver Sage $ 4,949 $ 4,107 $ 4,798 Busch Ranch Wind Farm $ 2,071 $ 1,734 $ 1,998 PPAs with Cargill (a) $ 10,995 $ 16,112 $ 9,286 ________________ (a) PPAs with Cargill expired on December 31, 2016. 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 . Natural Gas Delivery Commitment In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. This take or pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. The 10 year agreement expiring in 2024 became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes. 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, 2016 , 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 Enable-East NWPL-Wyoming SSTAR-TEXOK Other 2017 5,549,427 620,300 1,208,000 457,399 44,913 2018 — 584,000 1,208,000 — — 2019 — 584,000 720,000 — — 2020 — 585,600 — — — 2021 — 388,800 — — — Purchases under these contracts totaled $31 million, $48 million and $31 million for 2016, 2015 and 2014, respectively. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, gathering commitments, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation, storage, gathering and coal agreements 2017 $ 26,690 $ 136,607 2018 $ 8,934 $ 120,123 2019 $ 6,388 $ 87,210 2020 $ 6,388 $ 82,247 2021 $ 5,755 $ 75,424 Thereafter $ 11,509 $ 225,765 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 $2.6 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. • 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. • 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, 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, 2023 . This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. 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. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Air Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO 2 , NO x , mercury, hazardous air pollutants, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies. Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen I, Wygen II, Wygen III, Wyodak and Pueblo Airport Generating Station plants. Title IV of the Clean Air Act created an SO 2 allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2046. The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which imposed emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Ben French, Osage and Neil Simpson I on March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. This facility suspended operations December 31, 2012 and was retired on December 31, 2013. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the Consolidated Balance Sheet. The CPUC also approved a CPCN for the retirement of Pueblo Units #5 and #6 effective December 31, 2013. 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, 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 several 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 $1.5 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. 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. In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012. However, there was a potential for additional minimal remediation work at Plattsmouth where monitoring was required until 2015. Both Nebraska sites were required to monitor groundwater quality for a minimum two year period, ending in 2015. In late 2015, groundwater concentrations were proposed and approved by the Nebraska Department of Environmental Quality as meeting steady or declining pollution levels. We assembled our final removal action completion reports to formally close the site, and submitted reports to the Nebraska Department of Environmental Quality in December 2015. In 2016, we received state approval for “no further action” at both sites. As of December 31, 2016, our estimated liabilities for Iowa’s MGP sites currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of sites as of December 31, 2016 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted. As a result of the SourceGas Transaction, we acquired potential liability for at least one former MGP site in McCook, Nebraska. The Nebraska Department of Environmental Quality conducted a limited assessment in 2012 which documented soil and groundwater impacts. However, there has been no directive from the state to pursue either remediation or further assessment. We are currently evaluating the potential for other Potential Responsible Parties and future comprehensive analysis to fully determine and delineate the extent of contamination. The assigned liability for this site cannot be determined at this time. However, based on the state’s assessment, we anticipate costs will be less than $1.0 million . 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, 2016 | |
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, 2016 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 57,105 Ongoing $ 57,105 _______________________ (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. |
Oil and Gas Reserves (Unaudited
Oil and Gas Reserves (Unaudited): | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Reserves (Unaudited) | OIL AND GAS RESERVES (Unaudited) BHEP has operating and non-operating interests in 713 gross developed oil and gas wells in 9 states and holds leases on approximately 127,919 net acres. 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 2015 2014 Acquisition of properties: Proved $ — $ 1,407 $ 4,881 Unproved 910 669 5,056 Exploration costs 1,102 35,434 54,355 Development costs 4,657 128,998 52,262 Asset retirement obligations incurred — 566 68 Total costs incurred $ 6,669 $ 167,074 $ 116,622 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 , 2015 and 2014 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are 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 2015 2014 Oil Gas NGL Oil Gas NGL 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 4,276 65,440 1,720 3,921 63,190 — Production (a) (319 ) (9,430 ) (133 ) (371 ) (10,058 ) (102 ) (337 ) (7,156 ) (135 ) Sales (570 ) (1,291 ) (17 ) (11 ) (828 ) — (40 ) (61 ) — Additions - extensions and discoveries 3 52 — 199 24,462 232 733 11,003 182 Revisions to previous estimates (322 ) (8,173 ) 110 (643 ) (5,604 ) (98 ) (1 ) (1,536 ) 1,673 Balance at end of year 2,242 54,570 1,712 3,450 73,412 1,752 4,276 65,440 1,720 Proved developed reserves at end of year included above 2,242 54,570 1,712 3,436 73,390 1,752 3,780 57,427 1,530 Proved undeveloped reserves at the end of year included in above — — — 14 22 — 496 8,013 191 NYMEX prices $ 42.75 $ 2.48 $ — (b) $ 50.28 $ 2.59 $ — (b) $ 94.99 $ 4.35 $ — (b) Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 $ 44.72 $ 1.27 $ 18.96 $ 85.80 $ 3.33 $ 34.81 ________________________ (a) Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL is 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. Presently, ethane is 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. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. Reserve additions for 2016 totaled 0.1 Bcfe, replacing 0% of annual production. Reserve additions in 2016 were minimal due to continued poor economic conditions and our focus on supporting utility Cost of Service Gas Programs, which together, limited any further drilling. Capital spending in 2016 was primarily for existing infrastructure and acquiring right-aways. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program. In 2016 , we had negative revisions of ( 9.4 Bcfe) to previous reserve estimates. Most of the negative revision was the result of lower equivalent prices of oil, liquids and gas received at the wellhead of ( 12.3 Bcfe), partially offset by improved wellhead performance of 3.5 Bcfe. SEC regulations require that PUD locations meet the test of being developed within five years of being categorized as proved. In 2016 , we had no PUD locations that were required to be dropped because of the five year rule. Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year and investment and progress made in converting the PUD locations to proved developed during the year. • We have no PUDs at December 31, 2016, and due to economic conditions in 2016, no new gross PUD locations were added for future drilling in the Piceance Mancos or Powder River Basin. • The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2016 were: Proved Reserves (in Bcfe) Gross PUD Locations Future Development Costs (in millions) Existing 2015: Williston 0.1 6 $ 0.5 Piceance — — $ (0.1 ) Powder River — — $ — Year End Total 2015 0.1 6 $ 0.4 Dropped 2016: Williston (0.1 ) (6 ) $ (0.5 ) Piceance — — $ 0.1 (0.1 ) (6 ) $ (0.4 ) Drilled in 2016: — — $ — Revisions: — — $ — Added in 2016: — — $ — Total Proved Undeveloped — — $ — Capitalized Costs Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2016 2015 2014 Unproved oil and gas properties $ 18,547 $ 47,254 $ 75,329 Proved oil and gas properties 1,043,558 1,008,466 807,518 Gross capitalized costs 1,062,105 1,055,720 882,847 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) (888,775 ) (612,012 ) Net capitalized costs $ 62,014 $ 166,945 $ 270,835 Results of Operations Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2016 2015 2014 Revenue $ 34,058 $ 43,283 $ 55,114 Production costs 17,231 19,762 22,155 Depreciation, depletion and amortization 12,574 28,062 23,288 Impairment of long-lived assets 106,957 249,608 — Total costs 136,762 297,432 45,443 Results of operations from producing activities before tax (102,704 ) (254,149 ) 9,671 Income tax benefit (expense) 37,916 93,743 (3,415 ) Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) $ (160,406 ) $ 6,256 Unproved Properties Unproved properties not subject to amortization at December 31, 2016 , relate primarily to direct purchase leasehold and work-in-progress projects. Unproved properties not subject to amortization at December 31, 2015 and 2014 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 , $1.0 million and $1.0 million of interest during 2016 , 2015 and 2014 , respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties. However, the timing of the ultimate evaluation and disposition of the properties has not been determined. 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 2015 2014 Prior Total Leasehold acquisition cost $ 963 $ — $ — $ 9,278 $ 10,241 Exploration cost 532 441 6,443 — 7,416 Capitalized interest 50 23 335 482 890 Total $ 1,545 $ 464 $ 6,778 $ 9,760 $ 18,547 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 2015 2014 Future cash inflows $ 246,221 $ 295,173 $ 675,973 Future production costs (166,248 ) (146,552 ) (245,180 ) Future development costs, including plugging and abandonment (18,333 ) (24,833 ) (45,123 ) Future income tax expense — — (29,523 ) Future net cash flows 61,640 123,788 356,147 10% annual discount for estimated timing of cash flows (26,574 ) (44,760 ) (173,125 ) Standardized measure of discounted future net cash flows $ 35,066 $ 79,028 $ 183,022 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 2015 2014 Standardized measure - beginning of year $ 79,028 $ 183,022 $ 159,425 Sales and transfers of oil and gas produced, net of production costs (4,314 ) (29,948 ) (32,139 ) Net changes in prices and production costs (32,698 ) (127,199 ) (28,544 ) Extensions, discoveries and improved recovery, less related costs — 15,718 17,582 Changes in future development costs 1,825 (7,387 ) 3,195 Development costs incurred during the period — 27,211 2,079 Revisions of previous quantity estimates (7,477 ) (6,941 ) 23,722 Accretion of discount 7,903 18,870 18,437 Net change in income taxes — 5,682 19,265 Purchases of reserves — — — Sales of reserves (9,201 ) — — Standardized measure - end of year $ 35,066 $ 79,028 $ 183,022 Changes in the standardized measure from “revisions of previous quantity estimates” are 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 are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are 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, 2016 | |
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 2016 and 2015 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2016 Revenue $ 449,959 $ 325,441 $ 333,786 $ 463,788 Operating income (loss) $ 73,590 $ 35,298 $ 58,409 $ 55,289 Net Income (loss) $ 40,050 $ 3,283 $ 17,884 $ 21,414 Net income (loss) available for common stock $ 40,002 $ 669 $ 14,131 $ 18,168 Earnings (loss) per share - Basic $ 0.78 $ 0.01 $ 0.27 $ 0.34 Earnings (loss) per share - Diluted $ 0.77 $ 0.01 $ 0.26 $ 0.33 Dividends paid per share $ 0.420 $ 0.420 $ 0.420 $ 0.420 Common stock prices - High $ 61.13 $ 63.53 $ 64.58 $ 62.83 Common stock prices - Low $ 44.65 $ 56.16 $ 56.86 $ 54.76 All quarters of 2016 included non-cash impairments of oil and gas properties and external incremental acquisition and transaction costs. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2015 Revenue $ 441,987 $ 272,254 $ 272,105 $ 318,259 Operating income (loss) $ 70,500 $ (38,858 ) $ (2,044 ) $ 197 Net Income (loss) $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Net income (loss) available for common stock $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Earnings (loss) per share - Basic $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Earnings (loss) per share - Diluted $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Dividends paid per share $ 0.405 $ 0.405 $ 0.405 $ 0.405 Common stock prices - High $ 53.37 $ 52.96 $ 47.27 $ 47.51 Common stock prices - Low $ 47.88 $ 43.48 $ 36.81 $ 40.00 All quarters of 2015 included non-cash impairments of oil and gas properties. We incurred external incremental acquisition and transaction costs during the second, third and fourth quarters. We recorded after-tax impairments of oil and gas properties of $14 million during the first quarter, $66 million during the second quarter, $36 million during the third quarter and $44 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $0.5 million during the second quarter, $2.8 million during the third quarter and $3.7 million during the fourth quarter. |
Subsequent Event_
Subsequent Event: | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS None. |
Schedule II Consolidated Valuat
Schedule II Consolidated Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Valuation and Qualifying Accounts [Abstract] | |
Schedule II Consolidated Valuation and Qualifying Accounts | SCHEDULE II BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014 Description 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 (in thousands) Allowance for doubtful accounts: 2016 $ 1,741 $ 2,158 $ 2,704 $ 4,915 $ (9,126 ) $ 2,392 2015 $ 1,516 $ — $ 3,860 $ 4,132 $ (7,767 ) $ 1,741 2014 $ 1,237 $ — $ 4,470 $ 4,233 $ (8,424 ) $ 1,516 |
Business Description (Policies)
Business Description (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Business Description | Business Description Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated 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, Mining, and Oil and Gas. 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. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. 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 South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. 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. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program. |
Reclassifications | Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash and book overdrafts. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million , $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the consolidated balance sheet as of December 31, 2015 and to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported. |
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. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company 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 working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information. |
Variable Interest Entity | Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, 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 VIEs 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 it 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. |
Cash and Cash Equivalents, Restricted Cash and Equivalents | Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash. |
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, Oil and Gas, and Power Generation business segments consists of amounts due from sales of coal, crude oil and natural gas, 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 when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. |
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 valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. |
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 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 class 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. |
Oil and Gas Operations | Oil and Gas Operations We account for our oil and gas activities under the full cost method. 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. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length. 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. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31, 2016. See information on our oil and gas drilling activities in Note 21 . Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories. |
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. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. 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 and long-term earnings and merger multiples for comparable companies. 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. |
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, other than Oil and Gas. For the Oil and Gas segment, 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 depleted pursuant to our use of the full cost method. |
Fair Value Measurements | Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, or if they qualify for certain exemptions, including the normal purchases and normal sales exemption. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings. Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging. |
Derivatives, Offsetting Fair Value Amounts | 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. |
Deferred Financing Costs | Deferred Financing Costs Deferred financing costs are amortized using the effective interest method over the estimated useful life of the related debt. |
Development Costs | Development Costs According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income (Loss). |
Legal Costs | Legal Costs Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. |
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 would require these net 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 following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. |
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 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 carry forwards. 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. 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 generated 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 Income (loss) from continuing or 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, and 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 Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. |
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 and Adopted Accounting Standards Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). T his ASU requires changes in the pres entation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15 , 2017. We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments . This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) . The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected. Recently Issued and Adopted Accounting Standards Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). T his ASU requires changes in the pres entation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15 , 2017. We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments . This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) . The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected. |
Business Description (Tables)
Business Description (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Reclassifications | The following changes have been made to our Consolidated Statements of Income (Loss) to reflect combined revenue and combined operations and maintenance expenses, rather than by business group as previously reported, for the twelve months ended December 31, 2015 and December 31, 2014 respectively: Year Ended December 31, 2015 Year Ended December 31, 2014 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Revenue: Utilities $ 1,219,526 $ (1,219,526 ) $ — $ 1,300,969 $ (1,300,969 ) $ — Non-regulated energy $ 85,079 $ (85,079 ) $ — $ 92,601 $ (92,601 ) $ — Revenue $ — $ 1,304,605 $ 1,304,605 $ — $ 1,393,570 $ 1,393,570 Operating Expenses: Utilities - operations and maintenance $ 272,407 $ (272,407 ) $ — $ 270,954 $ (270,954 ) $ — Non-regulated energy operations and maintenance $ 88,702 $ (88,702 ) $ — $ 88,141 $ (88,141 ) $ — Operations and maintenance $ — $ 361,109 $ 361,109 $ — $ 359,095 $ 359,095 |
Accounts Receivable and Allowance for Doubtful Accounts | Following is a summary of accounts receivable as of December 31 (in thousands): 2016 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Oil and Gas 3,991 — (13 ) 3,978 Corporate 2,228 — — 2,228 Total $ 140,889 $ 124,792 $ (2,392 ) $ 263,289 2015 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,330 32,869 (1,001 ) 62,198 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,026 — — 1,026 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 ________________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015 , previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment. |
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 (in thousands): December 31, 2016 December 31, 2015 Materials and supplies $ 68,456 $ 55,726 Fuel - Electric Utilities 3,667 5,567 Natural gas in storage 35,087 25,650 Total materials, supplies and fuel $ 107,210 $ 86,943 |
Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2016 December 31, 2015 Accrued employee compensation, benefits and withholdings $ 56,926 $ 43,342 Accrued property taxes 40,004 32,393 Accrued payments related to litigation expenses and settlements — 38,750 Customer deposits and prepayments 51,628 53,496 Accrued interest and contract adjustment payments 45,503 25,762 Other (none of which is individually significant) 49,973 38,318 Total accrued liabilities $ 244,034 $ 232,061 |
Goodwill | Goodwill balances were as follows (in thousands): Electric Utilities (a) Gas Utilities (a) Power Generation Total Ending balance at December 31, 2014 $ 248,479 $ 96,152 $ 8,765 $ 353,396 Additions (b) — 6,363 — 6,363 Ending balance at December 31, 2015 $ 248,479 $ 102,515 $ 8,765 $ 359,759 Additions (c) — 939,695 — 939,695 Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 _________________ (a) Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details. (b) Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. (c) Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. |
Intangible Assets | Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2016 2015 2014 Intangible assets, net, beginning balance $ 3,380 $ 3,176 $ 3,397 Additions 5,522 434 — Amortization expense (a) (510 ) (230 ) (221 ) Intangible assets, net, ending balance $ 8,392 $ 3,380 $ 3,176 _________________ (a) 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 (in thousands): Maximum Amortization As of As of (in years) December 31, 2016 December 31, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a)(d) 1 $ 17,491 $ 24,751 Deferred gas cost adjustments (a)(d) 1 15,329 15,521 Gas price derivatives (a) 4 8,843 23,583 Deferred taxes on AFUDC (b) 45 15,227 12,870 Employee benefit plans (c) (e) 12 108,556 83,986 Environmental (a) subject to approval 1,108 1,180 Asset retirement obligations (a) 44 505 457 Loss on reacquired debt (a) 22 20,188 3,133 Renewable energy standard adjustment (a) 5 1,605 5,068 Deferred taxes on flow through accounting (c) 35 37,498 29,722 Decommissioning costs (b) 10 16,859 18,310 Gas supply contract termination (a) 5 26,666 — Other regulatory assets (a) 15 26,267 13,903 $ 296,142 $ 232,484 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 10,368 $ 7,814 Employee benefit plans (c) 12 68,654 47,218 Cost of removal (a) 44 118,410 90,045 Other regulatory liabilities (c) 25 9,324 7,964 $ 206,756 $ 153,041 __________ (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, respectively. (d) Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. (e) Increase compared to 2015 was driven by the addition of the SourceGas employee benefit plans. |
Earnings Per Share Reconciliation | A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands): December 31, 2016 December 31, 2015 December 31, 2014 Net income (loss) available for common stock $ 72,970 $ (32,111 ) $ 130,889 Weighted average shares - basic 51,922 45,288 44,394 Dilutive effect of: Equity Units 1,222 — — Equity compensation 127 — 204 Weighted average shares - diluted 53,271 45,288 44,598 Net income (loss) available for common stock, per share - Diluted $ 1.37 $ (0.71 ) $ 2.93 |
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 (in thousands): December 31, 2016 December 31, 2015 December 31, 2014 Equity compensation 3 112 81 Equity units — 6,440 — Anti-dilutive shares excluded from computation of earnings (loss) per share 3 6,552 81 |
Acquisition_ Acquisition (Table
Acquisition: Acquisition (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Business Combination, Separately Recognized Transactions | (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 |
Business Acquisition, Pro Forma Information [Table Text Block] | The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results December 31, 2016 2015 (in thousands, except per share amounts) Revenue $ 1,651,936 $ 1,763,901 Net income (loss) available for common stock $ 112,878 $ (13,369 ) Earnings (loss) per share, Basic $ 2.17 $ (0.26 ) Earnings (loss) per share, Diluted $ 2.12 $ (0.26 ) |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2016 2015 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 $ 1,303,101 41 $ 1,136,847 43 30 63 Electric transmission 354,801 52 280,257 50 40 70 Electric distribution 712,575 48 699,775 47 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 164,761 25 159,496 24 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,801,549 2,542,686 Construction work in progress 74,045 96,501 Total electric plant 2,875,594 2,639,187 Less accumulated depreciation and amortization 578,162 526,954 Electric plant net of accumulated depreciation and amortization (c) $ 2,297,432 $ 2,112,233 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 14 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. (c) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. 2016 2015 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 $ 10,821 35 $ 13 30 17 71 Gas transmission 338,729 48 45,104 60 22 70 Gas distribution 1,303,366 42 692,800 45 33 47 Cushion gas - depreciable (a) 3,539 28 — 0 28 28 Cushion gas - not depreciated (a) 47,055 0 — 0 0 0 Storage 27,686 31 — 0 15 48 General 339,382 19 122,109 22 3 44 Total gas plant in service 2,070,578 860,026 Construction work in progress 28,446 11,854 Total gas plant 2,099,024 871,880 Less accumulated depreciation and amortization 194,585 120,458 Gas plant net of accumulated depreciation and amortization (b) $ 1,904,439 $ 751,422 _____________ (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. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. 2016 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 $ 161,430 $ 1,298 $ 162,728 $ 55,157 $ 107,571 33 2 40 Mining 151,709 4,642 156,351 105,219 51,132 13 2 59 Oil and Gas (a) 1,101,106 — 1,101,106 1,016,226 84,880 25 2 25 _____________ (a) Net Property, Plant and Equipment includes full cost pool net assets of approximately $43 million . 2015 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 $ 156,721 $ 2,182 $ 158,903 $ 51,471 $ 107,432 33 2 40 Mining 154,630 3,649 158,279 97,663 60,616 13 2 59 Oil and Gas 1,132,776 — 1,132,776 925,908 206,868 24 3 25 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,446 $ 11,974 $ 17,420 $ (6,115 ) $ 23,535 8 3 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. 2015 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 376 $ 15,377 $ 15,753 $ (4,770 ) $ 20,523 10 5 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. |
Jointly Owned Facilities (Table
Jointly Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Jointly Owned Utility Plants | At December 31, 2016 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 113,611 $ 256 $ 55,878 Transmission Tie $ 19,978 $ 13 $ 5,793 Wygen I $ 109,412 $ 957 $ 37,156 Wygen III $ 138,261 $ 1,806 $ 17,635 Busch Ranch Wind Farm $ 18,899 $ — $ 3,102 |
Business Segments Information (
Business Segments Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting Information, Additional Information [Abstract] | |
Segment information included in Consolidated Balance Sheets | Segment information was as follows (in thousands): Total Assets (net of inter-company eliminations) as of December 31, 2016 2015 Electric (a) (d) $ 2,859,559 $ 2,704,330 Gas (b) (d) 3,307,967 999,778 Power Generation (a) 73,445 60,864 Mining 67,347 76,358 Oil and Gas 96,435 208,956 Corporate (c) 110,691 576,357 Total assets $ 6,515,444 $ 4,626,643 __________________ (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) Includes the assets acquired in the SourceGas acquisition on February 12, 2016. (c) Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million , previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2016 2015 Capital Expenditures Electric Utilities (b) $ 258,739 $ 171,897 Gas Utilities (b) 173,930 99,674 Power Generation 4,719 2,694 Mining 5,709 5,767 Oil and Gas 6,669 168,925 Corporate 17,353 9,864 Total Capital Expenditures 467,119 458,821 Asset Acquisitions Gas Utilities (b) (c) 1,124,238 21,970 Total Capital Expenditures and Asset Acquisitions $ 1,591,357 $ 480,791 _________________ (a) Includes accruals for property, plant and equipment. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. (c) SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2. The 2015 acquisitions represent two acquisitions made by Wyoming Gas. Property, Plant and Equipment as of December 31, 2016 2015 Electric Utilities (a) (b) $ 2,875,594 $ 2,639,187 Gas Utilities (b) (c) 2,099,024 871,880 Power Generation (a) 162,728 158,903 Mining 156,351 158,279 Oil and Gas 1,101,106 1,132,776 Corporate 17,420 15,753 Total property, plant and equipment $ 6,412,223 $ 4,976,778 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility Property, Plant and Equipment of $130 million , previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment. (c) Includes Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016. |
Segment information included in Consolidated Statements of Income | Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ 34,058 $ — $ — $ 1,572,974 Inter-company revenue 12,951 — 83,955 31,213 — 347,500 (475,619 ) — Total revenue 677,281 838,343 91,131 60,280 34,058 347,500 (475,619 ) 1,572,974 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 32,158 373,773 (326,847 ) 555,256 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 13,902 22,538 (23,827 ) 189,043 Impairment of long-lived assets (a) — — — — 106,957 — — 106,957 Operating income (loss) 173,153 162,017 54,391 11,358 (118,959 ) (49,267 ) (10,107 ) 222,586 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (4,864 ) (109,035 ) 115,469 (135,412 ) Interest income 5,946 1,573 1,983 24 — 97,147 (105,244 ) 1,429 Other income (expense), net 3,193 184 2 2,209 110 179,839 (181,034 ) 4,503 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 52,659 24,365 457 (10,475 ) Net income (loss) 85,827 59,726 35,489 10,053 (71,054 ) 143,049 (180,459 ) 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 $ (71,054 ) $ 143,049 $ (180,459 ) $ 72,970 ________________ (a) Oil and Gas includes oil and gas property impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2015 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 668,226 $ 551,300 $ 7,483 $ 34,313 $ 43,283 $ — $ — $ 1,304,605 Inter-company revenue 11,617 — 83,307 30,753 — 227,708 (353,385 ) — Total revenue 679,843 551,300 90,790 65,066 43,283 227,708 (353,385 ) 1,304,605 Fuel, purchased power and cost of natural gas sold 269,409 299,645 — — — 122 (112,289 ) 456,887 Operations and maintenance 160,924 140,723 32,140 41,630 41,593 225,721 (229,786 ) 412,945 Depreciation, depletion and amortization 80,929 32,326 4,329 9,806 29,287 9,273 (10,580 ) 155,370 Impairment of long-lived assets (a) — — — — 249,608 — — 249,608 Operating income (loss) 168,581 78,606 54,321 13,630 (277,205 ) (7,408 ) (730 ) 29,795 Interest expense (55,159 ) (17,912 ) (4,218 ) (433 ) (2,726 ) (57,839 ) 54,568 (83,719 ) Interest income 4,114 601 1,015 34 217 48,582 (52,942 ) 1,621 Other income (expense), net 1,216 315 71 2,247 (337 ) 70,889 (71,964 ) 2,437 Impairment of equity investments (a) — — — — (4,405 ) — — (4,405 ) Income tax benefit (expense) (41,173 ) (22,304 ) (18,539 ) (3,608 ) 104,498 2,926 360 22,160 Net income (loss) 77,579 39,306 32,650 11,870 (179,958 ) 57,150 (70,708 ) (32,111 ) Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 77,579 $ 39,306 $ 32,650 $ 11,870 $ (179,958 ) $ 57,150 $ (70,708 ) $ (32,111 ) ________________ (a) Oil and Gas includes ceiling test and equity investment impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2014 Electric Utilities Gas Utilities Power Generation Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 643,446 $ 657,523 $ 6,401 $ 31,086 $ 55,114 $ — $ — $ 1,393,570 Inter-company revenue 14,110 — 81,157 32,272 — 222,460 (349,999 ) — Total revenue 657,556 657,523 87,558 63,358 55,114 222,460 (349,999 ) 1,393,570 Fuel, purchased power and cost of natural gas sold 291,644 403,781 — — — 116 (113,759 ) 581,782 Operations and maintenance 156,252 142,024 33,126 41,172 42,659 213,415 (225,473 ) 403,175 Depreciation, depletion and amortization 77,011 28,912 4,540 10,276 24,246 7,690 (7,930 ) 144,745 Operating income (loss) 132,649 82,806 49,892 11,910 (11,791 ) 1,239 (2,837 ) 263,868 Interest expense (51,640 ) (17,487 ) (4,351 ) (493 ) (2,603 ) (50,299 ) 55,913 (70,960 ) Interest income 4,590 466 682 59 918 48,969 (53,759 ) 1,925 Other income (expense), net 1,074 124 (6 ) 2,275 183 61,605 (62,574 ) 2,681 Income tax benefit (expense) (29,403 ) (21,758 ) (17,701 ) (3,299 ) 4,768 24 744 (66,625 ) Net income (loss) 57,270 44,151 28,516 10,452 (8,525 ) 61,538 (62,513 ) 130,889 Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 57,270 $ 44,151 $ 28,516 $ 10,452 $ (8,525 ) $ 61,538 $ (62,513 ) $ 130,889 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Schedule of Long-term Debt Instruments | Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Due Date December 31, 2016 December 31, 2016 December 31, 2015 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 Corporate term loan due 2017 (a) — 300,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% 250,000 — Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 — Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 — Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 — Corporate term loan due 2019 (a) August 9, 2019 1.74% 400,000 — Corporate term loan due 2021 June 7, 2021 2.32% 24,406 — Total Corporate Debt 2,698,406 1,324,000 Less unamortized debt discount (4,413 ) (1,890 ) Total Corporate Debt, Net 2,693,993 1,322,110 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 0.72% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 0.72% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 0.88% 2,855 2,855 Total Electric Utilities Debt 544,855 544,855 Less unamortized debt discount (94 ) (99 ) Total Electric Utilities Debt 544,761 544,756 Total long-term debt 3,238,754 1,866,866 Less current maturities 5,743 — Less deferred financing costs (d) 21,822 13,184 Long-term debt, net of current maturities and deferred financing costs $ 3,211,189 $ 1,853,682 _______________ (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, 2016 and December 31, 2015 , 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): 2017 $ 5,743 2018 $ 5,743 2019 $ 655,742 2020 $ 205,742 2021 $ 8,436 Thereafter $ 2,361,855 |
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, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 Senior unsecured notes due 2023 2,921 494 494 653 Senior unsecured notes due 2019 763 643 — — Senior unsecured notes due 2020 592 167 167 167 Senior unsecured notes due 2026 2,318 262 — — Senior unsecured notes due 2027 3,281 121 — — Senior unsecured notes due 2046 3,193 37 — — Corporate term loan due 2019 287 144 — — Bridge Term Loan — 843 4,213 — RSNs due 2028 1,449 122 10 — First mortgage bonds due 2044 (South Dakota Electric) 663 24 24 6 First mortgage bonds due 2044 (Wyoming Electric) 613 23 22 6 First mortgage bonds due 2032 518 33 33 33 First mortgage bonds due 2039 1,734 76 76 76 First mortgage bonds due 2037 643 31 31 31 Other 506 304 43 53 Total $ 21,822 $ 3,861 $ 5,617 $ 1,641 The deferred financing costs on the new facility are being amortized as follows (in thousands): Deferred Financing Costs Remaining on Balance Sheet as of Amortization Expense for the years ended December 31, December 31, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 |
Notes Payable (Tables)
Notes Payable (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 December 31, 2015 Revolving Credit Facility $ 96,600 $ 76,800 |
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, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 Senior unsecured notes due 2023 2,921 494 494 653 Senior unsecured notes due 2019 763 643 — — Senior unsecured notes due 2020 592 167 167 167 Senior unsecured notes due 2026 2,318 262 — — Senior unsecured notes due 2027 3,281 121 — — Senior unsecured notes due 2046 3,193 37 — — Corporate term loan due 2019 287 144 — — Bridge Term Loan — 843 4,213 — RSNs due 2028 1,449 122 10 — First mortgage bonds due 2044 (South Dakota Electric) 663 24 24 6 First mortgage bonds due 2044 (Wyoming Electric) 613 23 22 6 First mortgage bonds due 2032 518 33 33 33 First mortgage bonds due 2039 1,734 76 76 76 First mortgage bonds due 2037 643 31 31 31 Other 506 304 43 53 Total $ 21,822 $ 3,861 $ 5,617 $ 1,641 The deferred financing costs on the new facility are being amortized as follows (in thousands): Deferred Financing Costs Remaining on Balance Sheet as of Amortization Expense for the years ended December 31, December 31, 2016 2016 2015 2014 Revolving Credit Facility $ 2,341 $ 537 $ 504 $ 616 |
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, 2016 Covenant Requirement at December 31, 2016 Consolidated Indebtedness to Capitalization Ratio 62 % Less than 70 % |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b)(c) December 31, 2016 Electric Utilities $ 4,462 $ — $ — $ 191 $ — $ 8 $ 4,661 Gas Utilities 136 — — 791 22,412 6,436 29,775 Mining 18,633 — (105 ) 822 — (6,910 ) 12,440 Oil and Gas 21,504 3 (2,049 ) 1,382 — 1,923 22,763 Total $ 44,735 $ 3 $ (2,154 ) $ 3,186 $ 22,412 $ 1,457 $ 69,639 December 31, 2014 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired Revisions to Prior Estimates (c) December 31, 2015 Electric Utilities $ 7,012 $ — $ (2,733 ) $ 183 $ — $ — $ 4,462 Gas Utilities 291 — (168 ) 13 — — 136 Mining 19,138 — — 993 — (1,498 ) 18,633 Oil and Gas 20,945 828 (1,792 ) 1,371 — 152 21,504 Total $ 47,386 $ 828 $ (4,693 ) $ 2,560 $ — $ (1,346 ) $ 44,735 _____________________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. The 2015 Mining Revision to Prior Estimates reflects a change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions. |
Risk Management Activities (Tab
Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments | The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2016 December 31, 2015 Interest Rate Swaps (a) Interest Rate Swaps (a) Interest Rate Swaps (b) Notional $ 50,000 $ 75,000 $ 250,000 Weighted average fixed interest rate 4.94 % 4.97 % 2.29 % Maximum terms in months 1 13 16 Derivative assets, non-current $ — $ — $ 3,441 Derivative liabilities, current $ 90 $ 2,835 $ — Derivative liabilities, non-current $ — $ 156 $ — ___________________ (a) The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. (b) These swaps were settled on August 19, 2016. |
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, 2016 December 31, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 14,770,000 48 20,580,000 60 Natural gas options purchased, net (b) 3,020,000 5 2,620,000 3 Natural gas basis swaps purchased 12,250,000 48 18,150,000 60 Natural gas over-the-counter swaps, net (c) 4,622,302 28 — 0 Natural gas physical commitments, net (d) 21,504,378 10 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions. (c) As of December 31, 2016 , 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased. (d) 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, 2016 and 2015 (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, 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 Revenue 11,019 — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) — Total impact from cash flow hedges $ 7,106 $ (953 ) December 31, 2015 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 $ (3,647 ) $ — Commodity derivatives Revenue 14,460 — Total $ 10,813 $ — December 31, 2014 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 $ (3,669 ) $ — Commodity derivatives Revenue (1,995 ) — Total $ (5,664 ) $ — 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, 2016 , 2015 and 2014 . 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, 2016 December 31, 2015 December 31, 2014 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ (31,222 ) $ 2,888 $ (536 ) Forward commodity contracts (573 ) 9,782 14,681 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 3,899 3,647 3,669 Forward commodity contracts (11,005 ) (14,460 ) 1,995 Total other comprehensive income (loss) from hedging $ (38,901 ) $ 1,857 $ 19,809 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, 2016 , 2015 and 2014 (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. 2016 2015 2014 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 Revenue $ (50 ) $ — $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold 940 — — $ 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 $8.8 million and $24 million at December 31, 2016 and 2015 , respectively. |
Oil and Gas | |
Derivative [Line Items] | |
Schedule of Derivative Instruments | The contract or notional amounts and terms of our crude oil futures and options and natural gas futures held at our Oil and Gas segment are comprised of short positions. A short position is a contract to sell the commodity while a long position is a contract to purchase the commodity. We had the following short positions as of: December 31, 2016 December 31, 2015 Crude oil futures and swaps (b) Crude oil options Natural gas futures and swaps (b) Crude oil futures and swaps (b) Natural gas futures and swaps (b) Notional (a) 108,000 36,000 2,700,000 198,000 4,392,500 Maximum terms in months (c) 24 12 24 24 24 ________________________ (a) Crude in Bbls, gas in MMBtus. (b) These financial instruments were designated as cash flow hedges upon inception. (c) Refers to the maximum forward period hedged. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas $ — $ 2,886 $ — $ (2,733 ) $ 153 Commodity derivatives - Utilities — 7,469 — (3,262 ) 4,207 Interest rate swaps — — — — — Total $ — $ 10,355 $ — $ (5,995 ) $ 4,360 Liabilities: Commodity derivatives - Oil and Gas $ — $ 1,586 $ — $ — $ 1,586 Commodity derivatives - Utilities — 12,201 — (11,144 ) 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 13,877 $ — $ (11,144 ) $ 2,733 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas $ — $ 10,644 $ — $ (10,644 ) $ — Commodity derivatives - Utilities — 2,293 — (2,293 ) — Interest rate swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives - Oil and Gas $ — $ 556 $ — $ (556 ) $ — Commodity derivatives - Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 |
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): 2016 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets - current $ 1,161 $ — $ 9,981 $ — Commodity derivatives Derivative assets - non-current 124 — 663 — Interest rate swaps Derivative assets - non-current — — 3,441 — Commodity derivatives Derivative liabilities - current — 1,090 — 465 Commodity derivatives Derivative liabilities - non-current — 238 — 91 Interest rate swaps Derivative liabilities - current — 90 — 2,835 Interest rate swaps Derivative liabilities - non-current — — — 156 Total derivatives designated as hedges $ 1,285 $ 1,418 $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ 2,977 $ — $ — $ — Commodity derivatives Derivative assets - non-current 98 — — — Commodity derivatives Derivative liabilities - current — 1,279 — 9,586 Commodity derivatives Derivative liabilities - non-current — 36 — 12,706 Interest rate swaps Derivative liabilities - current — — — — Interest rate swaps Derivative liabilities - non-current — — — — Total derivatives not designated as hedges $ 3,075 $ 1,315 $ — $ 22,292 |
Schedule of Derivative Offsetting on Balance Sheet | Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2016 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 Subject to master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 2,886 $ (2,733 ) $ 153 Utilities 4,269 (3,262 ) 1,007 Interest Rate Swaps — — — Total derivative assets subject to a master netting agreement or similar arrangement 7,155 (5,995 ) 1,160 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities 3,200 — 3,200 Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement 3,200 — 3,200 Total derivative assets $ 10,355 $ (5,995 ) $ 4,360 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 1,586 $ — $ 1,586 Utilities 11,144 (11,144 ) — Interest Rate Swaps — — — Total derivative liabilities subject to a master netting agreement or similar arrangement 12,730 (11,144 ) 1,586 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities 1,057 — 1,057 Interest Rate Swaps 90 — 90 Total derivative liabilities not subject to a master netting agreement or similar arrangement 1,147 — 1,147 Total derivative liabilities $ 13,877 $ (11,144 ) $ 2,733 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2015 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 Subject to master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 10,644 $ (10,644 ) $ — Utilities 2,293 (2,293 ) — Interest rate swaps 3,441 — 3,441 Total derivative assets subject to a master netting agreement or similar arrangement 16,378 (12,937 ) 3,441 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities — — — Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement — — — Total derivative assets $ 16,378 $ (12,937 ) $ 3,441 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas $ 556 $ (556 ) $ — Utilities 24,585 (24,585 ) — Interest Rate Swaps 2,991 — 2,991 Total derivative liabilities subject to a master netting agreement or similar arrangement 28,132 (25,141 ) 2,991 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas — — — Utilities — — — Interest Rate Swaps — — — Total derivative liabilities not subject to a master netting agreement or similar arrangement — — — Total derivative liabilities $ 28,132 $ (25,141 ) $ 2,991 |
Fair Value of Financial Instr44
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair value of financial instruments | The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 13,580 $ 13,580 $ 440,861 $ 440,861 Restricted cash and equivalents (a) $ 2,274 $ 2,274 $ 1,697 $ 1,697 Notes payable (b) $ 96,600 $ 96,600 $ 76,800 $ 76,800 Long-term debt, including current maturities (c) $ 3,216,932 $ 3,351,305 $ 1,853,682 $ 1,992,274 _______________ (a) Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. |
Equity_ (Tables)
Equity: (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Company's equity units | Selected information about our equity units is presented below (in thousands except for percentages) : Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability as of December 31, 2016 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 23,335 |
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): 2016 2015 2014 Stock-based compensation expense $ 10,885 $ 4,076 $ 9,329 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity | A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands): 2016 2015 Shares Issued 51 66 Weighted Average Price $ 58.24 $ 44.79 Unissued Shares Available 356 408 |
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: 2016 2015 (in thousands) Assets Current assets $ 12,627 $ — Property, plant and equipment of variable interest entities, net $ 218,798 $ — Liabilities Current liabilities $ 4,342 $ — |
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, 2016 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 202 $ 48.96 Granted 195 53.55 Vested (88 ) 48.00 Forfeited (14 ) 51.89 Balance at end of period 295 $ 52.15 |
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, 2014 January 1, 2014 - December 31, 2016 44 0% 200% January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% January 1, 2016 January 1, 2016 - December 31, 2018 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, 2016 (in thousands) (in thousands) Performance Shares balance at beginning of period 74 $ 47.21 74 Granted 27 47.76 27 Forfeited — — — Vested (30 ) 35.86 (30 ) Performance Shares balance at end of period 71 $ 52.29 71 $ 48.05 _____________________ (a) The grant date fair values for the performance shares granted in 2016 , 2015 and 2014 were determined by Monte Carlo simulation using a blended volatility of 24% , 21% and 23% , 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, 2016 $ 47.76 December 31, 2015 $ 54.92 December 31, 2014 $ 55.18 Performance plan payouts have been as follows (dollars and shares in thousands): Performance Period Year of Payment Shares Issued Cash Paid Total Intrinsic Value January 1, 2013 to December 31, 2015 2016 — $ — $ — January 1, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314 January 1, 2011 to December 31, 2013 2014 59 $ 3,011 $ 6,020 |
Operating Leases (Tables)
Operating Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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): 2016 2015 2014 Rent expense $ 9,568 $ 7,177 $ 6,932 |
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): 2017 $ 6,739 2018 $ 5,564 2019 $ 4,441 2020 $ 2,639 2021 $ 1,652 Thereafter $ 6,245 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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): 2016 2015 2014 Current: Federal $ (23,820 ) $ 2,549 $ (2,319 ) State (1,922 ) 1,319 (1,288 ) (25,742 ) 3,868 (3,607 ) Deferred: Federal 36,012 (23,592 ) 64,780 State 257 (2,323 ) 5,658 Tax credit amortization (52 ) (113 ) (206 ) 36,217 (26,028 ) 70,232 $ 10,475 $ (22,160 ) $ 66,625 |
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): 2016 2015 Deferred tax assets: Regulatory liabilities $ 58,200 $ 43,586 Employee benefits 29,638 26,400 Federal net operating loss 252,780 217,922 Other deferred tax assets (a) 83,485 85,907 Less: Valuation allowance (9,263 ) (4,304 ) Total deferred tax assets 414,840 369,511 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (b) (820,111 ) (711,293 ) Regulatory assets (49,471 ) (29,092 ) State deferred tax liability (47,987 ) (35,065 ) Deferred costs (18,551 ) (26,121 ) Other deferred tax liabilities (14,326 ) (18,519 ) Total deferred tax liabilities (950,446 ) (820,090 ) Net deferred tax liability $ (535,606 ) $ (450,579 ) _______________ (a) Other deferred tax assets consist primarily of state tax credits, state net operating loss, alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million , previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration. |
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: 2016 2015 2014 Federal statutory rate (e) 35.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 0.2 1.0 1.1 Amortization of excess deferred income taxes and investment tax credits (0.1 ) 0.2 (0.1 ) Percentage depletion (a) (8.2 ) 3.5 (1.0 ) Non-controlling interest (d) (3.6 ) — — Equity AFUDC (1.1 ) 0.3 (0.1 ) Tax credits (1.5 ) 0.5 (0.1 ) Transaction costs 1.1 — — Accounting for uncertain tax positions adjustment (b) (6.0 ) (3.5 ) (0.1 ) Flow-through adjustments (c) (5.1 ) 3.8 (0.9 ) Other tax differences 0.6 — (0.1 ) 11.3 % 40.8 % 33.7 % _________________________ (a) The tax benefit includes additional percentage depletion deductions that were claimed with respect to the oil and gas properties involving prior tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (b) The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. (c) The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. 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. (d) Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded. (e) The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net |
Summary of Operating Loss Carryforwards | At December 31, 2016 , we have federal and gross state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 721,075 2019 to 2036 State Net Operating Loss Carryforward $ 616,524 2017 to 2036 |
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, 2014 $ 37,631 Additions for prior year tax positions 1,253 Reductions for prior year tax positions (6,692 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2014 32,192 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 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 |
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, 2016 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 19,765 2023 to 2036 Research and development $ 167 No expiration |
Comprehensive Income (Loss) (Ta
Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 December 31, 2015 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (3,899 ) $ (3,647 ) Commodity contracts Revenue 11,019 14,460 Commodity contracts Fuel, purchased power and cost of natural gas sold (14 ) — 7,106 10,813 Income tax Income tax benefit (expense) (2,702 ) (4,271 ) Total reclassification adjustments related to cash flow hedges, net of tax $ 4,404 $ 6,542 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 221 $ 238 Actuarial gain (loss) Operations and maintenance (1,978 ) (2,822 ) (1,757 ) (2,584 ) Income tax Income tax benefit (expense) 533 884 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,224 ) $ (1,700 ) Total reclassifications $ 3,180 $ 4,842 |
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, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (20,302 ) (361 ) (1,985 ) (22,648 ) Amounts reclassified from AOCI 2,534 (6,938 ) 1,224 (3,180 ) As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2014 $ (4,930 ) $ 10,023 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss) before reclassifications 2,290 5,884 2,657 10,831 Amounts reclassified from AOCI 2,299 (8,841 ) 1,700 (4,842 ) As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Years ended December 31, 2016 2015 2014 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 29,082 $ 40,250 $ 52,584 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 8,577 $ (518 ) $ (5,634 ) Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (112,925 ) $ (77,810 ) $ (69,239 ) Income taxes, net $ (1,156 ) $ (1,202 ) $ (413 ) |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Defined Benefit Plans Disclosures | Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Postretirement benefit obligation $ 22,187 $ 11,751 |
Schedule of Allocation of Plan Assets | The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows: 2016 2015 Equity 28% 26% Real estate 5 5 Fixed income 57 59 Cash 2 1 Hedge funds 8 9 Total 100% 100% |
Schedule of Defined Contribution Plans Contributions | Contributions for the years ended December 31 were as follows (in thousands): 2016 2015 Defined Contribution Plan Company Retirement Contribution $ 9,632 $ 5,564 Matching contributions $ 9,645 $ 9,616 2016 2015 Defined Benefit Plans Defined Benefit Pension Plans $ 14,200 $ 10,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 4,965 $ 3,771 Supplemental Non-Qualified Defined Benefit Plans $ 1,565 $ 1,564 |
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 statement of financial position, components of the net periodic expense and elements of AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Projected benefit obligation at beginning of year $ 356,575 $ 377,772 $ 40,219 $ 41,211 $ 48,077 $ 49,042 Transfer from SourceGas Acquisition 75,254 — — — 15,091 — Service cost 7,619 6,093 2,099 1,300 1,757 1,808 Interest cost 15,743 15,522 1,257 1,455 1,942 1,801 Actuarial (gain) loss (a) 7,001 (28,229 ) 2,049 (2,072 ) 2,808 (1,206 ) Amendments — — — — 2,203 — Benefits paid (22,013 ) (14,583 ) (1,755 ) (1,675 ) (4,965 ) (3,771 ) Medicare Part D accrued — — — — — (178 ) Plan participants’ contributions — — — — 1,110 581 Projected benefit obligation at end of year $ 440,179 $ 356,575 $ 43,869 $ 40,219 $ 68,023 $ 48,077 ____________________ (a) Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates. |
Schedule of Changes in Fair Value of Plan Assets | Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans (a) 2016 2015 2016 2015 2016 2015 Beginning fair value of plan assets $ 288,622 $ 299,533 $ — $ — $ 4,681 $ 4,705 Transfer from SourceGas Acquisition 53,067 — — — 3,340 — Investment income (loss) 30,819 (6,528 ) — — 256 (9 ) Employer contributions 14,200 10,200 — — 4,048 3,175 Retiree contributions — — — — 1,110 581 Benefits paid (22,013 ) (14,583 ) — — (4,965 ) (3,771 ) Plan administrative expenses — — — — — — Ending fair value of plan assets $ 364,695 $ 288,622 $ — $ — $ 8,470 $ 4,681 ____________________ (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 Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Regulatory assets $ 66,640 $ 68,915 $ — $ — $ 11,401 $ 6,464 Current liabilities $ — $ — $ 1,583 $ 1,568 $ 4,360 $ 3,543 Non-current assets $ — $ — $ — $ — $ 21 $ 23 Non-current liabilities $ 75,484 $ 67,953 $ 42,286 $ 38,651 $ 55,214 $ 39,855 Regulatory liabilities $ 5,195 $ — $ — $ — $ 3,419 $ 3,209 |
Schedule of Accumulated and Projected Benefit Obligations | Accumulated Benefit Obligation (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Accumulated Benefit Obligation (a) $ 416,786 $ 334,923 $ 32,090 $ 30,558 $ 68,023 $ 48,077 ____________________ (a) The Defined Benefit Pension Plans Accumulated Benefit Obligation for 2016 represents the obligation for the merged Black Hills Retirement Plan. The 2015 obligation represents the BHC Pension Plan and Black Hills Utility Holding, Inc. Pension Plan and has been combined for presentation purposes to conform to the 2016 merged plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2016 represents that obligation for the five postretirement plans maintained by BHC. The 2015 obligation represents the three postretirement plans maintained by BHC. |
Components of net periodic benefit cost | Components of Net Periodic Expense (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2014 2016 2015 2014 2016 2015 2014 Service cost $ 7,619 $ 6,093 $ 5,448 $ 1,335 $ 1,380 $ 1,498 $ 1,757 $ 1,808 $ 1,700 Interest cost 15,743 15,522 15,852 1,257 1,455 1,447 1,942 1,801 1,919 Expected return on assets (23,062 ) (19,470 ) (18,065 ) — — — (279 ) (131 ) (85 ) Net amortization of prior service cost 58 58 62 2 2 2 (428 ) (428 ) (428 ) Recognized net actuarial loss (gain) 7,173 11,037 4,806 829 1,081 498 335 408 160 Settlement Expense (a) 10 — — — — — — — — Net periodic expense $ 7,541 $ 13,240 $ 8,103 $ 3,423 $ 3,918 $ 3,445 $ 3,327 $ 3,458 $ 3,266 ____________________ (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 Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2016 2015 2016 2015 2016 2015 Net (gain) loss $ 8,472 $ 8,777 $ 7,132 $ 6,339 $ 1,595 $ 1,704 Prior service cost (gain) 31 41 5 6 (694 ) (1,087 ) Total AOCI $ 8,503 $ 8,818 $ 7,137 $ 6,345 $ 901 $ 617 |
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year | The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2017 are as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 2,604 $ 572 $ 325 Prior service cost (credit) 38 1 (368 ) Total net periodic benefit cost expected to be recognized during calendar year 2017 $ 2,642 $ 573 $ (43 ) |
Schedule of Assumptions Used | Assumptions Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.27 % 4.58 % 4.19 % 4.02 % 4.28 % 4.19 % 3.96 % 4.17 % 3.82 % Rate of increase in compensation levels 3.47 % 3.51 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plans 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: 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate (a) 4.50 % 4.19 % 5.04 % 4.28 % 4.19 % 5.03 % 4.18 % 3.82 % 4.46 % Expected long-term rate of return on assets (b) 6.87 % 6.75 % 6.75 % N/A N/A N/A 3.83 % 3.00 % 2.00 % Rate of increase in compensation levels 3.42 % 3.76 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Retirement Plan is 4.27% for the calculation of the 2017 net periodic pension costs. (b) The expected rate of return on plan assets is 6.75% for the calculation of the 2017 net periodic pension cost. |
Schedule of Health Care Cost Trend Rates | The healthcare benefit obligation was determined at December 31 as follows: 2016 (a) 2015 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.35% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2024 2024 Post-65 for next year - All Plans 5.10% 5.20% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2023 2023 _____________________________ (a) The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas. |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands): Change in Assumed Trend Rate Impact on December 31, 2016 Accumulated Postretirement Benefit Obligation Impact on 2017 Service and Interest Cost Increase 1% $ 2,569 $ 156 Decrease 1% $ (2,191 ) $ (131 ) |
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 2017 $ 21,355 $ 1,583 $ 5,504 2018 $ 21,566 $ 1,809 $ 5,779 2019 $ 23,010 $ 1,921 $ 5,886 2020 $ 27,028 $ 1,634 $ 5,983 2021 $ 27,614 $ 1,836 $ 5,931 2022-2026 $ 149,893 $ 11,009 $ 27,585 |
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): Defined Benefit Pension Plans December 31, 2016 Level 1 Level 2 Level 3 NAV (a) Total AXA Equitable General Fixed Income $ — $ 1,325 $ — — $ 1,325 Common Collective Trust - Cash and Cash Equivalents — 5,307 — — 5,307 Common Collective Trust - Equity — 101,020 — — 101,020 Common Collective Trust - Fixed Income — 209,815 — — 209,815 Common Collective Trust - Real Estate — 2,349 — 15,563 17,912 Hedge Funds — — — 29,316 29,316 Total investments measured at fair value $ — $ 319,816 $ — $ 44,879 $ 364,695 Defined Benefit Pension Plans December 31, 2015 Level 1 Level 2 Level 3 NAV (a) Total AXA Equitable General Fixed Income $ — $ 1,072 $ — $ — $ 1,072 Common Collective Trust - Cash and Cash Equivalents — 1,556 — — 1,556 Common Collective Trust - Equity — 74,885 — — 74,885 Common Collective Trust - Fixed Income — 172,016 — — 172,016 Common Collective Trust - Real Estate — 2,204 — 11,143 13,347 Hedge Funds — — — 25,746 25,746 Total investments measured at fair value $ — $ 251,733 $ — $ 36,889 $ 288,622 _____________ (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. |
Postretirement Health Coverage | |
Defined Benefit Plan Disclosure [Line Items] | |
Schedule of Allocation of Plan Assets | Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2016 Level 1 Level 2 Level 3 Total Cash and Cash Equivalents $ 111 $ — $ — $ 111 Equity Securities 1,154 — — 1,154 Registered Investment Company Trust - Money Market Mutual Fund — 4,732 — 4,732 Intermediate-term Bond — 2,473 — 2,473 Total investments measured at fair value $ 1,265 $ 7,205 $ — $ 8,470 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2015 Level 1 Level 2 Level 3 Total Registered Investment Company Trust - Money Market Mutual Fund $ — $ 4,681 $ — $ 4,681 Total investments measured at fair value $ — $ 4,681 $ — $ 4,681 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, gathering commitments, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation, storage, gathering and coal agreements 2017 $ 26,690 $ 136,607 2018 $ 8,934 $ 120,123 2019 $ 6,388 $ 87,210 2020 $ 6,388 $ 82,247 2021 $ 5,755 $ 75,424 Thereafter $ 11,509 $ 225,765 |
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): 2016 2015 2014 PPA with PacifiCorp $ 12,221 $ 13,990 $ 13,943 Transmission services agreement with PacifiCorp $ 1,428 $ 1,213 $ 1,227 PPA with Happy Jack $ 3,836 $ 3,155 $ 3,919 PPA with Silver Sage $ 4,949 $ 4,107 $ 4,798 Busch Ranch Wind Farm $ 2,071 $ 1,734 $ 1,998 PPAs with Cargill (a) $ 10,995 $ 16,112 $ 9,286 ________________ (a) PPAs with Cargill expired on December 31, 2016. |
Purchased Gas Cost Obligation | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment | At December 31, 2016 , 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 Enable-East NWPL-Wyoming SSTAR-TEXOK Other 2017 5,549,427 620,300 1,208,000 457,399 44,913 2018 — 584,000 1,208,000 — — 2019 — 584,000 720,000 — — 2020 — 585,600 — — — 2021 — 388,800 — — — |
Guarantees (Tables)
Guarantees (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 57,105 Ongoing $ 57,105 _______________________ (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. |
Oil and Gas Reserves (Unaudit53
Oil and Gas Reserves (Unaudited): Oil and Gas Exploration and Production Industries Disclosure (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2015 2014 Acquisition of properties: Proved $ — $ 1,407 $ 4,881 Unproved 910 669 5,056 Exploration costs 1,102 35,434 54,355 Development costs 4,657 128,998 52,262 Asset retirement obligations incurred — 566 68 Total costs incurred $ 6,669 $ 167,074 $ 116,622 |
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 , 2015 and 2014 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are 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 2015 2014 Oil Gas NGL Oil Gas NGL 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 4,276 65,440 1,720 3,921 63,190 — Production (a) (319 ) (9,430 ) (133 ) (371 ) (10,058 ) (102 ) (337 ) (7,156 ) (135 ) Sales (570 ) (1,291 ) (17 ) (11 ) (828 ) — (40 ) (61 ) — Additions - extensions and discoveries 3 52 — 199 24,462 232 733 11,003 182 Revisions to previous estimates (322 ) (8,173 ) 110 (643 ) (5,604 ) (98 ) (1 ) (1,536 ) 1,673 Balance at end of year 2,242 54,570 1,712 3,450 73,412 1,752 4,276 65,440 1,720 Proved developed reserves at end of year included above 2,242 54,570 1,712 3,436 73,390 1,752 3,780 57,427 1,530 Proved undeveloped reserves at the end of year included in above — — — 14 22 — 496 8,013 191 NYMEX prices $ 42.75 $ 2.48 $ — (b) $ 50.28 $ 2.59 $ — (b) $ 94.99 $ 4.35 $ — (b) Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 $ 44.72 $ 1.27 $ 18.96 $ 85.80 $ 3.33 $ 34.81 ________________________ (a) Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL is 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. Presently, ethane is 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. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
Schedule of Oil and Gas In Process Activities | The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2016 were: Proved Reserves (in Bcfe) Gross PUD Locations Future Development Costs (in millions) Existing 2015: Williston 0.1 6 $ 0.5 Piceance — — $ (0.1 ) Powder River — — $ — Year End Total 2015 0.1 6 $ 0.4 Dropped 2016: Williston (0.1 ) (6 ) $ (0.5 ) Piceance — — $ 0.1 (0.1 ) (6 ) $ (0.4 ) Drilled in 2016: — — $ — Revisions: — — $ — Added in 2016: — — $ — Total Proved Undeveloped — — $ — |
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 2015 2014 Unproved oil and gas properties $ 18,547 $ 47,254 $ 75,329 Proved oil and gas properties 1,043,558 1,008,466 807,518 Gross capitalized costs 1,062,105 1,055,720 882,847 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) (888,775 ) (612,012 ) Net capitalized costs $ 62,014 $ 166,945 $ 270,835 |
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 2015 2014 Revenue $ 34,058 $ 43,283 $ 55,114 Production costs 17,231 19,762 22,155 Depreciation, depletion and amortization 12,574 28,062 23,288 Impairment of long-lived assets 106,957 249,608 — Total costs 136,762 297,432 45,443 Results of operations from producing activities before tax (102,704 ) (254,149 ) 9,671 Income tax benefit (expense) 37,916 93,743 (3,415 ) Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) $ (160,406 ) $ 6,256 |
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 2015 2014 Prior Total Leasehold acquisition cost $ 963 $ — $ — $ 9,278 $ 10,241 Exploration cost 532 441 6,443 — 7,416 Capitalized interest 50 23 335 482 890 Total $ 1,545 $ 464 $ 6,778 $ 9,760 $ 18,547 |
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 2015 2014 Future cash inflows $ 246,221 $ 295,173 $ 675,973 Future production costs (166,248 ) (146,552 ) (245,180 ) Future development costs, including plugging and abandonment (18,333 ) (24,833 ) (45,123 ) Future income tax expense — — (29,523 ) Future net cash flows 61,640 123,788 356,147 10% annual discount for estimated timing of cash flows (26,574 ) (44,760 ) (173,125 ) Standardized measure of discounted future net cash flows $ 35,066 $ 79,028 $ 183,022 |
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 2015 2014 Standardized measure - beginning of year $ 79,028 $ 183,022 $ 159,425 Sales and transfers of oil and gas produced, net of production costs (4,314 ) (29,948 ) (32,139 ) Net changes in prices and production costs (32,698 ) (127,199 ) (28,544 ) Extensions, discoveries and improved recovery, less related costs — 15,718 17,582 Changes in future development costs 1,825 (7,387 ) 3,195 Development costs incurred during the period — 27,211 2,079 Revisions of previous quantity estimates (7,477 ) (6,941 ) 23,722 Accretion of discount 7,903 18,870 18,437 Net change in income taxes — 5,682 19,265 Purchases of reserves — — — Sales of reserves (9,201 ) — — Standardized measure - end of year $ 35,066 $ 79,028 $ 183,022 |
Quarterly Historical Data (Un54
Quarterly Historical Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 and 2015 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2016 Revenue $ 449,959 $ 325,441 $ 333,786 $ 463,788 Operating income (loss) $ 73,590 $ 35,298 $ 58,409 $ 55,289 Net Income (loss) $ 40,050 $ 3,283 $ 17,884 $ 21,414 Net income (loss) available for common stock $ 40,002 $ 669 $ 14,131 $ 18,168 Earnings (loss) per share - Basic $ 0.78 $ 0.01 $ 0.27 $ 0.34 Earnings (loss) per share - Diluted $ 0.77 $ 0.01 $ 0.26 $ 0.33 Dividends paid per share $ 0.420 $ 0.420 $ 0.420 $ 0.420 Common stock prices - High $ 61.13 $ 63.53 $ 64.58 $ 62.83 Common stock prices - Low $ 44.65 $ 56.16 $ 56.86 $ 54.76 All quarters of 2016 included non-cash impairments of oil and gas properties and external incremental acquisition and transaction costs. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2015 Revenue $ 441,987 $ 272,254 $ 272,105 $ 318,259 Operating income (loss) $ 70,500 $ (38,858 ) $ (2,044 ) $ 197 Net Income (loss) $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Net income (loss) available for common stock $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Earnings (loss) per share - Basic $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Earnings (loss) per share - Diluted $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Dividends paid per share $ 0.405 $ 0.405 $ 0.405 $ 0.405 Common stock prices - High $ 53.37 $ 52.96 $ 47.27 $ 47.51 Common stock prices - Low $ 47.88 $ 43.48 $ 36.81 $ 40.00 All quarters of 2015 included non-cash impairments of oil and gas properties. We incurred external incremental acquisition and transaction costs during the second, third and fourth quarters. We recorded after-tax impairments of oil and gas properties of $14 million during the first quarter, $66 million during the second quarter, $36 million during the third quarter and $44 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $0.5 million during the second quarter, $2.8 million during the third quarter and $3.7 million during the fourth quarter. |
Business Description And Sign55
Business Description And Significant Accounting Policies: Segment Reporting (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue | $ 463,788 | $ 333,786 | $ 325,441 | $ 449,959 | $ 318,259 | $ 272,105 | $ 272,254 | $ 441,987 | $ 1,572,974 | $ 1,304,605 | $ 1,393,570 |
Operations and maintenance | $ 456,399 | 361,109 | 359,095 | ||||||||
Utilities Group | |||||||||||
Revenue | 0 | 0 | |||||||||
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses | 0 | 0 | |||||||||
Non Regulated Energy Group | |||||||||||
Revenue | 0 | 0 | |||||||||
Operating Costs, Nonregulated Energy Operations | 0 | 0 | |||||||||
Sales Revenue, Net | |||||||||||
Prior Period Reclassification Adjustment | 1,304,605 | 1,393,570 | |||||||||
Sales Revenue, Net | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | 0 | 0 | |||||||||
Sales Revenue, Net | Utilities Group | |||||||||||
Prior Period Reclassification Adjustment | (1,219,526) | (1,300,969) | |||||||||
Sales Revenue, Net | Utilities Group | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | 1,219,526 | 1,300,969 | |||||||||
Sales Revenue, Net | Non Regulated Energy Group | |||||||||||
Prior Period Reclassification Adjustment | (85,079) | (92,601) | |||||||||
Sales Revenue, Net | Non Regulated Energy Group | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | 85,079 | 92,601 | |||||||||
Operating Expense | |||||||||||
Prior Period Reclassification Adjustment | 361,109 | 359,095 | |||||||||
Operating Expense | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | 0 | 0 | |||||||||
Operating Expense | Utilities Group | |||||||||||
Prior Period Reclassification Adjustment | (272,407) | (270,954) | |||||||||
Operating Expense | Utilities Group | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | 272,407 | 270,954 | |||||||||
Operating Expense | Non Regulated Energy Group | |||||||||||
Prior Period Reclassification Adjustment | (88,702) | (88,141) | |||||||||
Operating Expense | Non Regulated Energy Group | Scenario, Previously Reported | |||||||||||
Prior Period Reclassification Adjustment | $ 88,702 | $ 88,141 |
Business Description And Sign56
Business Description And Significant Accounting Policies: Reclassifications (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2016 | |
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | $ 0.8 | |||
Net Cash Provided By Operating Activities | ||||
Prior Period Reclassification Adjustment | $ 3.7 | $ 8.1 | ||
Cash and Cash Equivalents | ||||
Prior Period Reclassification Adjustment | $ 16 | $ 12 | $ 3.8 |
Business Description And Sign57
Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | $ (1,741) | $ (2,392) |
Accounts receivable, net | 147,486 | 263,289 |
Corporate, Non-Segment | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | 0 | 0 |
Accounts receivable, net | 1,026 | 2,228 |
Electric Utilities | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (727) | (353) |
Accounts receivable, net | 76,826 | 77,840 |
Electric Utilities | Trade Accounts Receivable [Member] | ||
Accounts Receivable [Line Items] | ||
Prior Period Reclassification Adjustment | (6,800) | |
Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (1,001) | (2,026) |
Accounts receivable, net | 62,198 | 174,471 |
Gas Utilities | Trade Accounts Receivable [Member] | ||
Accounts Receivable [Line Items] | ||
Prior Period Reclassification Adjustment | 6,800 | |
Power Generation | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | 0 | 0 |
Accounts receivable, net | 1,187 | 1,420 |
Mining | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | 0 | 0 |
Accounts receivable, net | 2,760 | 3,352 |
Oil and Gas | ||
Accounts Receivable [Line Items] | ||
Allowance for Doubtful Accounts | (13) | (13) |
Accounts receivable, net | 3,489 | 3,978 |
Billed Revenues | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 80,484 | 140,889 |
Billed Revenues | Corporate, Non-Segment | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 1,026 | 2,228 |
Billed Revenues | Electric Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 41,679 | 41,730 |
Billed Revenues | Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 30,330 | 88,168 |
Billed Revenues | Power Generation | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 1,187 | 1,420 |
Billed Revenues | Mining | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 2,760 | 3,352 |
Billed Revenues | Oil and Gas | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 3,502 | 3,991 |
Unbilled Revenues | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 68,743 | 124,792 |
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 | 35,874 | 36,463 |
Unbilled Revenues | Gas Utilities | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | 32,869 | 88,329 |
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 |
Unbilled Revenues | Oil and Gas | ||
Accounts Receivable [Line Items] | ||
Accounts Receivable, Trade | $ 0 | $ 0 |
Business Description And Sign58
Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Materials and supplies | $ 68,456 | $ 55,726 |
Fuel - Electric Utilities | 3,667 | 5,567 |
Natural gas in storage | 35,087 | 25,650 |
Total materials, supplies and fuel | $ 107,210 | $ 86,943 |
Business Description And Sign59
Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accrued employee compensation, benefits and withholdings | $ 56,926 | $ 43,342 |
Accrued property taxes | 40,004 | 32,393 |
Accrued payments related to litigation expenses and settlements | 0 | 38,750 |
Customer deposits and prepayments | 51,628 | 53,496 |
Accrued interest and contract adjustment payments | 45,503 | 25,762 |
Other (none of which is individually significant) | 49,973 | 38,318 |
Total accrued liabilities | $ 244,034 | $ 232,061 |
Business Description And Sign60
Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Roll Forward] | |||
Goodwill, Beginning Balance | $ 359,759 | $ 353,396 | |
Goodwill | 939,695 | 6,363 | |
Goodwill, Ending Balance | 1,299,454 | 359,759 | $ 353,396 |
Electric Utilities | |||
Goodwill [Roll Forward] | |||
Goodwill, Beginning Balance | 248,479 | 248,479 | |
Goodwill | 0 | 0 | |
Goodwill, Ending Balance | 248,479 | 248,479 | 248,479 |
Electric Utilities | Goodwill [Member] | |||
Goodwill [Line Items] | |||
Prior Period Reclassification Adjustment | 2,000 | 6,300 | |
Gas Utilities | |||
Goodwill [Roll Forward] | |||
Goodwill, Beginning Balance | 102,515 | 96,152 | |
Goodwill | 939,695 | 6,363 | |
Goodwill, Ending Balance | 1,042,210 | 102,515 | 96,152 |
Gas Utilities | Goodwill [Member] | |||
Goodwill [Line Items] | |||
Prior Period Reclassification Adjustment | (2,000) | (6,300) | |
Power Generation | |||
Goodwill [Roll Forward] | |||
Goodwill, Beginning Balance | 8,765 | 8,765 | |
Goodwill | 0 | 0 | |
Goodwill, Ending Balance | $ 8,765 | $ 8,765 | $ 8,765 |
Aquila Transaction | Electric Utilities | |||
Goodwill [Line Items] | |||
Goodwill Allocation by Segment (percentage) | 72.00% | ||
Goodwill [Roll Forward] | |||
Goodwill, Ending Balance | $ 246,000 | ||
Aquila Transaction | Gas Utilities | |||
Goodwill [Line Items] | |||
Goodwill Allocation by Segment (percentage) | 28.00% | ||
Goodwill [Roll Forward] | |||
Goodwill, Ending Balance | $ 94,000 | ||
SourceGas Transaction | Gas Utilities | |||
Goodwill [Roll Forward] | |||
Goodwill, Ending Balance | $ 940,000 |
Business Description And Sign61
Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Finite-Lived Intangible Assets [Roll Forward] | |||
Intangible assets, net, beginning balance | $ 3,380 | $ 3,176 | $ 3,397 |
Intangible assets, additions | 5,522 | 434 | 0 |
Intangible assets, amortization expense | (510) | (230) | (221) |
Intangible assets, net, ending balance | 8,392 | $ 3,380 | $ 3,176 |
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 |
Business Description And Sign62
Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) $ in Thousands | Apr. 29, 2016USD ($)$ / Btu | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 296,142 | $ 232,484 | |
Regulatory liabilities | $ 206,756 | 153,041 | |
Deferred energy, fuel and gas cost adjustments - current | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities maximum amortization period | 1 year | ||
Regulatory liabilities | $ 10,368 | 7,814 | |
Employee benefit plans | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities maximum amortization period | 12 years | ||
Regulatory liabilities | $ 68,654 | 47,218 | |
Cost of removal | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities maximum amortization period | 44 years | ||
Regulatory liabilities | $ 118,410 | 90,045 | |
Other regulatory liabilities | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory liabilities maximum amortization period | 25 years | ||
Regulatory liabilities | $ 9,324 | 7,964 | |
Deferred energy, fuel and gas cost adjustments - current | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 1 year | ||
Regulatory assets | $ 17,491 | 24,751 | |
Deferred gas cost adjustments | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 1 year | ||
Regulatory assets | $ 15,329 | 15,521 | |
Gas price derivatives | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 4 years | ||
Regulatory assets | $ 8,843 | 23,583 | |
Deferred taxes on AFUDC | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 45 years | ||
Regulatory assets | $ 15,227 | 12,870 | |
Employee benefit plans | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 12 years | ||
Regulatory assets | $ 108,556 | 83,986 | |
Environmental | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets | $ 1,108 | 1,180 | |
Asset retirement obligations | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 44 years | ||
Regulatory assets | $ 505 | 457 | |
Loss on reacquired debt | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 22 years | ||
Regulatory assets | $ 20,188 | 3,133 | |
Renewable energy standard adjustment | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 5 years | ||
Regulatory assets | $ 1,605 | 5,068 | |
Deferred taxes on flow through accounting | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 35 years | ||
Regulatory assets | $ 37,498 | 29,722 | |
Decommissioning costs | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 10 years | ||
Regulatory assets | $ 16,859 | 18,310 | |
Gas supply contract termination | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 5 years | 5 years | |
Regulatory assets | $ 30,000 | $ 26,666 | 0 |
Other regulatory assets | |||
Schedule of Regulatory Assets and Liabilities [line items] | |||
Regulatory assets maximum amortization period | 15 years | ||
Regulatory assets | $ 26,267 | $ 13,903 | |
Minimum | |||
Settlement of Gas Supply Contract [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 6 | ||
Minimum | Gas supply contract termination | |||
Settlement of Gas Supply Contract [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 6 | ||
Maximum | |||
Settlement of Gas Supply Contract [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 8 | ||
Maximum | Gas supply contract termination | |||
Settlement of Gas Supply Contract [Abstract] | |||
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu | 8 |
Business Description And Sign63
Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||
Net income (loss) available for common stock | $ 18,168 | $ 14,131 | $ 669 | $ 40,002 | $ (14,176) | $ (9,943) | $ (41,842) | $ 33,850 | $ 72,970 | $ (32,111) | $ 130,889 |
Weighted average shares - Basic (in shares) | 51,922,000 | 45,288,000 | 44,394,000 | ||||||||
Dilutive effect of: | |||||||||||
Equity Units (in shares) | 1,222,000 | 0 | 0 | ||||||||
Equity compensation (in shares) | 127,000 | 0 | 204,000 | ||||||||
Weighted average shares - diluted (in shares) | 53,271,000 | 45,288,000 | 44,598,000 | ||||||||
Earnings (loss) per share, Diluted (usd per share) | $ 0.33 | $ 0.26 | $ 0.01 | $ 0.77 | $ (0.30) | $ (0.22) | $ (0.94) | $ 0.76 | $ 1.37 | $ (0.71) | $ 2.93 |
Equity compensation shares excluded (in shares) | 83,000 |
Business Description And Sign64
Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 3 | 6,552 | 81 |
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) | 3 | 112 | 81 |
Equity Unit Purchase Agreements | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 0 | 6,440 | 0 |
Business Description And Sign65
Business Description And Significant Accounting Policies: Balance Sheet Classification of Debt Issuance Costs (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Other Assets, Non-Current | |
Prior Period Reclassification Adjustment | $ (13) |
Long-term Debt | |
Prior Period Reclassification Adjustment | $ (13) |
Acquisition (Details)
Acquisition (Details) $ / shares in Units, $ in Thousands | Apr. 29, 2016USD ($)$ / Btu | Feb. 12, 2016USD ($)customerutilitymi | Jan. 13, 2016USD ($) | Nov. 23, 2015USD ($)shares | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($) |
Acquisition Narrative [Abstract] | |||||||||||||||
Ownership of subsidiary (percent) | 99.50% | ||||||||||||||
Cash consideration paid | $ 1,135,000 | ||||||||||||||
Proceeds from issuance of shares | $ 536,000 | ||||||||||||||
Long-term debt - issuance | $ 546,000 | 1,767,608 | $ 300,000 | $ 160,000 | |||||||||||
Revenue | $ 463,788 | $ 333,786 | $ 325,441 | $ 449,959 | $ 318,259 | $ 272,105 | $ 272,254 | $ 441,987 | 1,572,974 | 1,304,605 | 1,393,570 | ||||
Net income (loss) available for common stock | 18,168 | $ 14,131 | $ 669 | $ 40,002 | (14,176) | $ (9,943) | $ (41,842) | $ 33,850 | 72,970 | (32,111) | 130,889 | ||||
Cash consideration paid | $ (1,124,238) | 1,124,238 | 21,970 | 0 | |||||||||||
Decrease of goodwill | 6,700 | ||||||||||||||
Acquisition Recap [Abstract] | |||||||||||||||
Consideration Paid, net of working capital adjustment received | $ (1,124,238) | 1,124,238 | 21,970 | 0 | |||||||||||
Goodwill | 1,299,454 | 359,759 | 1,299,454 | 359,759 | 353,396 | ||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Settlement of gas supply contract | $ 40,000 | ||||||||||||||
Contract committed to distribution customers, percent | 75.00% | ||||||||||||||
Contract not subject to regulatory recovery, percent | 25.00% | ||||||||||||||
Regulatory assets | $ 296,142 | 232,484 | $ 296,142 | 232,484 | |||||||||||
Pro Forma Results | |||||||||||||||
Estimated combined federal and state income tax rate (percent) | 37.00% | ||||||||||||||
Noncontrolling Interest [Abstract] | |||||||||||||||
Sellers retention (percent) | 0.50% | 0.50% | |||||||||||||
Gas Supply Contract Termination | |||||||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Regulatory assets | $ 30,000 | $ 26,666 | 0 | $ 26,666 | 0 | ||||||||||
Recovery period | 5 years | 5 years | |||||||||||||
Minimum | |||||||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Contract prices | $ / Btu | 6 | ||||||||||||||
Minimum | Gas Supply Contract Termination | |||||||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Contract prices | $ / Btu | 6 | ||||||||||||||
Maximum | |||||||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Contract prices | $ / Btu | 8 | ||||||||||||||
Maximum | Gas Supply Contract Termination | |||||||||||||||
Settlement of Gas Supply Contract [Abstract] | |||||||||||||||
Contract prices | $ / Btu | 8 | ||||||||||||||
Corporate, Non-Segment | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Pre-tax, incremental acquisition costs | $ 45,000 | 10,000 | |||||||||||||
Revenue | 347,500 | 227,708 | 222,460 | ||||||||||||
Net income (loss) available for common stock | $ 143,049 | $ 57,150 | 61,538 | ||||||||||||
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 | 1,968,738 | 6,325,000 | ||||||||||||
Source Gas | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
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 | ||||||||||||||
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 | ||||||||||||||
Current Assets | 112,983 | ||||||||||||||
Property, plant & equipment, net | 1,058,093 | ||||||||||||||
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 | 1,651,936 | $ 1,763,901 | |||||||||||||
Net income (loss) available for common stock | $ 112,878 | $ (13,369) | |||||||||||||
Earnings (loss) per share, Basic (usd per share) | $ / shares | $ 2.17 | $ (0.26) | |||||||||||||
Earnings (loss) per share, Diluted (usd per share) | $ / shares | $ 2.12 | $ (0.26) | |||||||||||||
Source Gas | Black Hills Energy, Arkansas | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Duration Of Base Rate Moratorium Imposed by ASPC | 12 months | ||||||||||||||
Annual Amount of Customer Credit | $ 250 | ||||||||||||||
Source Gas | Black Hills Energy, Arkansas | Maximum | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Duration Of Annual Customer Credit | 5 years | ||||||||||||||
Source Gas | Rocky Mountain Natural Gas | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Duration of Base Rate Moratorium imposed by CPUC | 2 years | ||||||||||||||
Source Gas | Black Hills Gas Distribution, Colorado | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Annual Amount of Customer Credit | 200 | ||||||||||||||
Duration of Base Rate Moratorium imposed by CPUC | 3 years | ||||||||||||||
Source Gas | Black Hills Gas Distribution, Colorado | Maximum | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Duration Of Annual Customer Credit | 5 years | ||||||||||||||
Source Gas | Black Hills Gas Distribution - Nebraska | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Duration of Base Rate Moratorium imposed by NPSC | 3 years | ||||||||||||||
Continuation Period of Choice Gas Program | 3 years | ||||||||||||||
Source Gas | Black Hills Gas Distribution - Wyoming | |||||||||||||||
Public Utilities, Rate Matters, Approved [Abstract] | |||||||||||||||
Continuation Period of Choice Gas Program | 3 years | ||||||||||||||
Gas Utilities | |||||||||||||||
Acquisition Narrative [Abstract] | |||||||||||||||
Revenue | 838,343 | $ 551,300 | 657,523 | ||||||||||||
Net income (loss) available for common stock | 59,624 | 39,306 | 44,151 | ||||||||||||
Acquisition Recap [Abstract] | |||||||||||||||
Goodwill | 1,042,210 | $ 102,515 | 1,042,210 | $ 102,515 | $ 96,152 | ||||||||||
Gas Utilities | SourceGas Transaction | |||||||||||||||
Acquisition Recap [Abstract] | |||||||||||||||
Goodwill | $ 939,695 | $ 940,000 | $ 940,000 |
Property, Plant and Equipment67
Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 6,412,223 | $ 4,976,778 |
Less: accumulated depreciation, depletion and amortization | 1,943,234 | 1,717,684 |
Total property, plant and equipment, net | 4,468,989 | 3,259,094 |
Oil and Gas Property, Full Cost Method, Net | 43,000 | |
Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 17,420 | 15,753 |
Total property, plant and equipment, net | 23,535 | 20,523 |
Property, plant and equipment | 5,446 | 376 |
Construction in progress, gross | 11,974 | 15,377 |
Intercompany Eliminations | ||
Property, Plant and Equipment [Line Items] | ||
Less: accumulated depreciation, depletion and amortization | $ (6,115) | $ (4,770) |
Weighted Average | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 8 years | 10 years |
Minimum | Corporate, Non-Segment | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 3 years | 5 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 | $ 2,801,549 | $ 2,542,686 |
Construction work in progress | 74,045 | 96,501 |
Property, plant and equipment, gross | 2,875,594 | 2,639,187 |
Less: accumulated depreciation, depletion and amortization | 578,162 | 526,954 |
Total property, plant and equipment, net | $ 2,297,432 | 2,112,233 |
Depreciation, depletion and amortization, remaining amortization period | 14 years | |
Electric Utilities | Property, Plant and Equipment Net Of Accumulated Depreciation | ||
Property, Plant and Equipment [Line Items] | ||
Prior Period Reclassification Adjustment | (117,000) | |
Electric Utilities | Production, Electric | ||
Property, Plant and Equipment [Line Items] | ||
Production | $ 1,303,101 | $ 1,136,847 |
Electric Utilities | Production, Electric | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 41 years | 43 years |
Electric Utilities | Production, Electric | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 30 years | |
Electric Utilities | Production, Electric | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 63 years | |
Electric Utilities | Electric transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 354,801 | $ 280,257 |
Electric Utilities | Electric transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 52 years | 50 years |
Electric Utilities | Electric transmission | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 40 years | |
Electric Utilities | Electric transmission | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 70 years | |
Electric Utilities | Electric distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 712,575 | $ 699,775 |
Electric Utilities | Electric distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | 47 years |
Electric Utilities | Electric distribution | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 15 years | |
Electric Utilities | Electric distribution | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 75 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 | $ 164,761 | $ 159,496 |
Electric Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 25 years | 24 years |
Electric Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 3 years | |
Electric Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 65 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] | ||
Production | $ 10,821 | $ 13 |
Total plant in service before construction work in progress | 2,070,578 | 860,026 |
Construction work in progress | 28,446 | 11,854 |
Property, plant and equipment, gross | 2,099,024 | 871,880 |
Less: accumulated depreciation, depletion and amortization | 194,585 | 120,458 |
Total property, plant and equipment, net | $ 1,904,439 | $ 751,422 |
Gas Utilities | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 35 years | 30 years |
Gas Utilities | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 17 years | |
Gas Utilities | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 71 years | |
Gas Utilities | Property, Plant and Equipment Net Of Accumulated Depreciation | ||
Property, Plant and Equipment [Line Items] | ||
Prior Period Reclassification Adjustment | $ 117,000 | |
Gas Utilities | General | ||
Property, Plant and Equipment [Line Items] | ||
General | $ 339,382 | $ 122,109 |
Gas Utilities | General | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 19 years | 22 years |
Gas Utilities | General | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 3 years | |
Gas Utilities | General | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 44 years | |
Gas Utilities | Gas transmission | ||
Property, Plant and Equipment [Line Items] | ||
Transmission | $ 338,729 | $ 45,104 |
Gas Utilities | Gas transmission | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | 60 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 | 70 years | |
Gas Utilities | Gas distribution | ||
Property, Plant and Equipment [Line Items] | ||
Distribution | $ 1,303,366 | $ 692,800 |
Gas Utilities | Gas distribution | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 42 years | 45 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 | $ 3,539 | $ 0 |
Gas Utilities | Cushion Gas - Depreciable | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 28 years | 0 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 | $ 47,055 | $ 0 |
Gas Utilities | Cushion Gas - Not Depreciated | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 0 years | 0 years |
Gas Utilities | Cushion Gas - Not Depreciated | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 0 years | |
Gas Utilities | Cushion Gas - Not Depreciated | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 0 years | |
Gas Utilities | Production, Gas | ||
Property, Plant and Equipment [Line Items] | ||
Production | $ 27,686 | $ 0 |
Gas Utilities | Production, Gas | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 31 years | 0 years |
Gas Utilities | Production, Gas | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 15 years | |
Gas Utilities | Production, Gas | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 48 years | |
Power Generation | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 162,728 | $ 158,903 |
Less: accumulated depreciation, depletion and amortization | 55,157 | 51,471 |
Total property, plant and equipment, net | 107,571 | 107,432 |
Property, plant and equipment | 161,430 | 156,721 |
Construction in progress, gross | $ 1,298 | $ 2,182 |
Power Generation | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 33 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 | $ 156,351 | $ 158,279 |
Less: accumulated depreciation, depletion and amortization | 105,219 | 97,663 |
Total property, plant and equipment, net | 51,132 | 60,616 |
Property, plant and equipment | 151,709 | 154,630 |
Construction in progress, gross | $ 4,642 | $ 3,649 |
Mining | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 13 years | 13 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 |
Oil and Gas | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 1,101,106 | $ 1,132,776 |
Less: accumulated depreciation, depletion and amortization | 1,016,226 | 925,908 |
Total property, plant and equipment, net | 84,880 | 206,868 |
Property, plant and equipment | 1,101,106 | 1,132,776 |
Construction in progress, gross | $ 0 | $ 0 |
Oil and Gas | Weighted Average | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 25 years | 24 years |
Oil and Gas | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 2 years | 3 years |
Oil and Gas | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Weighted average useful life | 25 years | 25 years |
Jointly Owned Facilities (Detai
Jointly Owned Facilities (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Electric Utilities | Wyodak Plant | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 20.00% |
Plant in Service | $ 113,611 |
Construction Work in Progress | 256 |
Accumulated Depreciation | $ 55,878 |
Electric Utilities | Transmission Tie | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 35.00% |
Plant in Service | $ 19,978 |
Construction Work in Progress | 13 |
Accumulated Depreciation | $ 5,793 |
Electric Utilities | Wygen I I I Generating Facility | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 52.00% |
Plant in Service | $ 138,261 |
Construction Work in Progress | 1,806 |
Accumulated Depreciation | $ 17,635 |
Electric Utilities | Busch Ranch Wind Farm | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 50.00% |
Plant in Service | $ 18,899 |
Construction Work in Progress | 0 |
Accumulated Depreciation | $ 3,102 |
Power Generation | Wygen I Generating Facility | |
Jointly Owned Utility Plant Interests [Line Items] | |
Ownership Share Percentage | 76.50% |
Plant in Service | $ 109,412 |
Construction Work in Progress | 957 |
Accumulated Depreciation | $ 37,156 |
Business Segments Information_
Business Segments Information: Segment Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 4,626,643 | $ 6,515,444 |
Corporate, Non-Segment | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 576,357 | 110,691 |
Electric Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 2,704,330 | 2,859,559 |
Electric Utilities | Assets | ||
Segment Reporting, Asset Reconciling Item | ||
Prior Period Reclassification Adjustment | (135,000) | |
Gas Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 999,778 | 3,307,967 |
Gas Utilities | Assets | ||
Segment Reporting, Asset Reconciling Item | ||
Prior Period Reclassification Adjustment | 135,000 | |
Power Generation | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 60,864 | 73,445 |
Mining | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 76,358 | 67,347 |
Oil and Gas | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 208,956 | $ 96,435 |
Business Segments Information70
Business Segments Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands | Feb. 12, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | $ 467,119 | $ 458,821 | ||
Acquisition of net assets, net of long-term debt assumed | $ 1,124,238 | (1,124,238) | (21,970) | $ 0 |
Property, Plant and Equipment Including New Asset Acquisitions, Gross Period Increase (Decrease) | 1,591,357 | 480,791 | ||
Gas Utilities | ||||
Segment Reporting Information [Line Items] | ||||
Acquisition of net assets, net of long-term debt assumed | 1,124,238 | 21,970 | ||
Source Gas | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | $ 1,124,000 | |||
Corporate, Non-Segment | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | 17,353 | 9,864 | ||
Electric Utilities | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | 258,739 | 171,897 | ||
Electric Utilities | Capital Expenditures | ||||
Segment Reporting Information [Line Items] | ||||
Prior Period Reclassification Adjustment | (30,000) | |||
Gas Utilities | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | 173,930 | 99,674 | ||
Gas Utilities | Capital Expenditures | ||||
Segment Reporting Information [Line Items] | ||||
Prior Period Reclassification Adjustment | 30,000 | |||
Power Generation | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | 4,719 | 2,694 | ||
Mining | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | 5,709 | 5,767 | ||
Oil and Gas | ||||
Segment Reporting Information [Line Items] | ||||
Capital Expenditures and Asset Acquisitions | $ 6,669 | $ 168,925 |
Business Segments Information71
Business Segments Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 4,976,778 | $ 6,412,223 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 15,753 | 17,420 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 2,639,187 | 2,875,594 |
Electric Utilities | Property, Plant and Equipment | ||
Segment Reporting Information [Line Items] | ||
Prior Period Reclassification Adjustment | (130,000) | |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 871,880 | 2,099,024 |
Gas Utilities | Property, Plant and Equipment | ||
Segment Reporting Information [Line Items] | ||
Prior Period Reclassification Adjustment | 130,000 | |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 158,903 | 162,728 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 158,279 | 156,351 |
Oil and Gas | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 1,132,776 | $ 1,101,106 |
Business Segments Information72
Business Segments Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information | |||||||||||
Revenue | $ 463,788 | $ 333,786 | $ 325,441 | $ 449,959 | $ 318,259 | $ 272,105 | $ 272,254 | $ 441,987 | $ 1,572,974 | $ 1,304,605 | $ 1,393,570 |
Fuel, purchased power and cost of natural gas sold | 499,132 | 456,887 | 581,782 | ||||||||
Operations and maintenance | 555,256 | 412,945 | 403,175 | ||||||||
Depreciation, depletion and amortization | 189,043 | 155,370 | 144,745 | ||||||||
Impairment of long-lived assets | 106,957 | 249,608 | 0 | ||||||||
Operating income | 55,289 | 58,409 | 35,298 | 73,590 | 197 | (2,044) | (38,858) | 70,500 | 222,586 | 29,795 | 263,868 |
Interest expense | (135,412) | (83,719) | (70,960) | ||||||||
Interest income | 1,429 | 1,621 | 1,925 | ||||||||
Other income (expense), net | 4,503 | 2,437 | 2,681 | ||||||||
Impairment of equity investments | 0 | (4,405) | 0 | ||||||||
Income tax benefit (expense) | (10,475) | 22,160 | (66,625) | ||||||||
Net income (loss) | 82,631 | (32,111) | 130,889 | ||||||||
Net income attributable to noncontrolling interest | (9,661) | 0 | 0 | ||||||||
Net income (loss) available for common stock | $ 18,168 | $ 14,131 | $ 669 | $ 40,002 | $ (14,176) | $ (9,943) | $ (41,842) | $ 33,850 | 72,970 | (32,111) | 130,889 |
Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 664,330 | 668,226 | 643,446 | ||||||||
Fuel, purchased power and cost of natural gas sold | 261,349 | 269,409 | 291,644 | ||||||||
Operations and maintenance | 158,134 | 160,924 | 156,252 | ||||||||
Depreciation, depletion and amortization | 84,645 | 80,929 | 77,011 | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | 173,153 | 168,581 | 132,649 | ||||||||
Interest expense | (56,237) | (55,159) | (51,640) | ||||||||
Interest income | 5,946 | 4,114 | 4,590 | ||||||||
Other income (expense), net | 3,193 | 1,216 | 1,074 | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | (40,228) | (41,173) | (29,403) | ||||||||
Net income (loss) | 85,827 | 77,579 | 57,270 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 85,827 | 77,579 | 57,270 | ||||||||
Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 838,343 | 551,300 | 657,523 | ||||||||
Fuel, purchased power and cost of natural gas sold | 352,165 | 299,645 | 403,781 | ||||||||
Operations and maintenance | 245,826 | 140,723 | 142,024 | ||||||||
Depreciation, depletion and amortization | 78,335 | 32,326 | 28,912 | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | 162,017 | 78,606 | 82,806 | ||||||||
Interest expense | (76,586) | (17,912) | (17,487) | ||||||||
Interest income | 1,573 | 601 | 466 | ||||||||
Other income (expense), net | 184 | 315 | 124 | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | (27,462) | (22,304) | (21,758) | ||||||||
Net income (loss) | 59,726 | 39,306 | 44,151 | ||||||||
Net income attributable to noncontrolling interest | (102) | 0 | 0 | ||||||||
Net income (loss) available for common stock | 59,624 | 39,306 | 44,151 | ||||||||
Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 7,176 | 7,483 | 6,401 | ||||||||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||||||||
Operations and maintenance | 32,636 | 32,140 | 33,126 | ||||||||
Depreciation, depletion and amortization | 4,104 | 4,329 | 4,540 | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | 54,391 | 54,321 | 49,892 | ||||||||
Interest expense | (3,758) | (4,218) | (4,351) | ||||||||
Interest income | 1,983 | 1,015 | 682 | ||||||||
Other income (expense), net | 2 | 71 | (6) | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | (17,129) | (18,539) | (17,701) | ||||||||
Net income (loss) | 35,489 | 32,650 | 28,516 | ||||||||
Net income attributable to noncontrolling interest | (9,559) | 0 | 0 | ||||||||
Net income (loss) available for common stock | 25,930 | 32,650 | 28,516 | ||||||||
Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 29,067 | 34,313 | 31,086 | ||||||||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||||||||
Operations and maintenance | 39,576 | 41,630 | 41,172 | ||||||||
Depreciation, depletion and amortization | 9,346 | 9,806 | 10,276 | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | 11,358 | 13,630 | 11,910 | ||||||||
Interest expense | (401) | (433) | (493) | ||||||||
Interest income | 24 | 34 | 59 | ||||||||
Other income (expense), net | 2,209 | 2,247 | 2,275 | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | (3,137) | (3,608) | (3,299) | ||||||||
Net income (loss) | 10,053 | 11,870 | 10,452 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 10,053 | 11,870 | 10,452 | ||||||||
Oil and Gas | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 34,058 | 43,283 | 55,114 | ||||||||
Fuel, purchased power and cost of natural gas sold | 0 | 0 | 0 | ||||||||
Operations and maintenance | 32,158 | 41,593 | 42,659 | ||||||||
Depreciation, depletion and amortization | 13,902 | 29,287 | 24,246 | ||||||||
Impairment of long-lived assets | 106,957 | 249,608 | |||||||||
Operating income | (118,959) | (277,205) | (11,791) | ||||||||
Interest expense | (4,864) | (2,726) | (2,603) | ||||||||
Interest income | 0 | 217 | 918 | ||||||||
Other income (expense), net | 110 | (337) | 183 | ||||||||
Impairment of equity investments | (4,405) | ||||||||||
Income tax benefit (expense) | 52,659 | 104,498 | 4,768 | ||||||||
Net income (loss) | (71,054) | (179,958) | (8,525) | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | (71,054) | (179,958) | (8,525) | ||||||||
Intercompany Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | (475,619) | (353,385) | (349,999) | ||||||||
Fuel, purchased power and cost of natural gas sold | (114,838) | (112,289) | (113,759) | ||||||||
Operations and maintenance | (326,847) | (229,786) | (225,473) | ||||||||
Depreciation, depletion and amortization | (23,827) | (10,580) | (7,930) | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | (10,107) | (730) | (2,837) | ||||||||
Interest expense | 115,469 | 54,568 | 55,913 | ||||||||
Interest income | (105,244) | (52,942) | (53,759) | ||||||||
Other income (expense), net | (181,034) | (71,964) | (62,574) | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | 457 | 360 | 744 | ||||||||
Net income (loss) | (180,459) | (70,708) | (62,513) | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | (180,459) | (70,708) | (62,513) | ||||||||
Intercompany Eliminations | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 12,951 | 11,617 | 14,110 | ||||||||
Intercompany Eliminations | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | 0 | 0 | ||||||||
Intercompany Eliminations | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 83,955 | 83,307 | 81,157 | ||||||||
Intercompany Eliminations | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 31,213 | 30,753 | 32,272 | ||||||||
Intercompany Eliminations | Oil and Gas | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 0 | 0 | 0 | ||||||||
Operating Segments | Electric Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 677,281 | 679,843 | 657,556 | ||||||||
Operating Segments | Gas Utilities | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 838,343 | 551,300 | 657,523 | ||||||||
Operating Segments | Power Generation | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 91,131 | 90,790 | 87,558 | ||||||||
Operating Segments | Mining | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 60,280 | 65,066 | 63,358 | ||||||||
Operating Segments | Oil and Gas | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 34,058 | 43,283 | 55,114 | ||||||||
Corporate, Non-Segment | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | 347,500 | 227,708 | 222,460 | ||||||||
Fuel, purchased power and cost of natural gas sold | 456 | 122 | 116 | ||||||||
Operations and maintenance | 373,773 | 225,721 | 213,415 | ||||||||
Depreciation, depletion and amortization | 22,538 | 9,273 | 7,690 | ||||||||
Impairment of long-lived assets | 0 | 0 | |||||||||
Operating income | (49,267) | (7,408) | 1,239 | ||||||||
Interest expense | (109,035) | (57,839) | (50,299) | ||||||||
Interest income | 97,147 | 48,582 | 48,969 | ||||||||
Other income (expense), net | 179,839 | 70,889 | 61,605 | ||||||||
Impairment of equity investments | 0 | ||||||||||
Income tax benefit (expense) | 24,365 | 2,926 | 24 | ||||||||
Net income (loss) | 143,049 | 57,150 | 61,538 | ||||||||
Net income attributable to noncontrolling interest | 0 | 0 | 0 | ||||||||
Net income (loss) available for common stock | 143,049 | 57,150 | 61,538 | ||||||||
Consolidation, Eliminations | |||||||||||
Segment Reporting Information | |||||||||||
Revenue | $ 0 | $ 0 | $ 0 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2016 | Aug. 19, 2016 | Jun. 07, 2016 | Jan. 13, 2016 | Dec. 31, 2015 | Nov. 23, 2015 | |
Debt Instrument [Line Items] | ||||||
Total long-term debt | $ 3,238,754 | $ 1,866,866 | ||||
Less current maturities | (5,743) | 0 | ||||
Less deferred financing costs | (21,822) | (13,184) | ||||
Long-term debt, net of current maturities | 3,211,189 | 1,853,682 | ||||
Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Less deferred financing costs | (2,300) | (1,700) | ||||
Electric Utilities | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 544,855 | 544,855 | ||||
Less unamortized debt discount | (94) | (99) | ||||
Total long-term debt | $ 544,761 | 544,756 | ||||
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) | 6.13% | |||||
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, Maturity Date | Sep. 1, 2021 | |||||
Long-term Debt, Variable Interest Rate | 0.72% | |||||
Long-term debt | $ 7,000 | 7,000 | ||||
Electric Utilities | Industrial Development Revenue Bonds Due 2027 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Maturity Date | Mar. 1, 2027 | |||||
Long-term Debt, Variable Interest Rate | 0.72% | |||||
Long-term debt | $ 10,000 | 10,000 | ||||
Electric Utilities | Series 94 A Debt, Due 2024 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Variable Interest Rate | 0.88% | |||||
Long-term debt | $ 2,855 | 2,855 | ||||
Black Hills Corporation | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 2,698,406 | 1,324,000 | ||||
Less unamortized debt discount | (4,413) | (1,890) | ||||
Total long-term debt | $ 2,693,993 | 1,322,110 | ||||
Black Hills Corporation | Senior Unsecured Notes Due 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 4.25% | |||||
Long-term debt | $ 525,000 | 525,000 | ||||
Black Hills Corporation | Senior Unsecured Notes Due 2020 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 5.875% | |||||
Long-term debt | $ 200,000 | 200,000 | ||||
Black Hills Corporation | Remarketable Junior Subordinated Notes Due 2028 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.50% | 3.50% | ||||
Long-term debt | $ 299,000 | 299,000 | $ 299,000 | |||
Black Hills Corporation | London Interbank Offered Rate (LIBOR) | Corporate Term Loan Due April 2017 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $ 0 | 300,000 | ||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 2.50% | 2.50% | ||||
Long-term debt | $ 250,000 | $ 250,000 | 0 | |||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.95% | 3.95% | ||||
Long-term debt | $ 300,000 | $ 300,000 | 0 | |||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 3.15% | 3.15% | ||||
Long-term debt | $ 400,000 | $ 400,000 | 0 | |||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 4.20% | 4.20% | ||||
Long-term debt | $ 300,000 | $ 300,000 | 0 | |||
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate (percent) | 2.32% | 2.32% | ||||
Long-term debt | $ 24,406 | $ 29,000 | 0 | |||
Black Hills Corporation | Corporate, Non-Segment | London Interbank Offered Rate (LIBOR) | Corporate Term Loan Due August 2019 | ||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt, Variable Interest Rate | 1.7447% | |||||
Long-term debt | $ 400,000 | 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, 2016 | Dec. 31, 2015 |
Long-term Debt, Unclassified [Abstract] | ||
2,017 | $ 5,743 | $ 0 |
2,018 | 5,743 | |
2,019 | 655,742 | |
2,020 | 205,742 | |
2,021 | 8,436 | |
Thereafter | $ 2,361,855 |
Long-Term Debt_ Assumption Of L
Long-Term Debt: Assumption Of Long-Term Debt (Details) - Source Gas - USD ($) $ in Thousands | Aug. 19, 2016 | Feb. 12, 2016 |
Debt Instrument [Line Items] | ||
Assumed long-term debt | $ 760,000 | |
Senior Unsecured Notes Due 2017 | ||
Debt Instrument [Line Items] | ||
Assumed long-term debt | $ 325,000 | |
Interest rate (percent) | 5.90% | 5.90% |
Senior Secured Notes Due 2019 | ||
Debt Instrument [Line Items] | ||
Assumed long-term debt | $ 95,000 | |
Interest rate (percent) | 3.98% | 3.98% |
Corporate Term Loan Due June 2017 | ||
Debt Instrument [Line Items] | ||
Assumed long-term debt | $ 340,000 | |
Corporate Term Loan Due June 2017 | London Interbank Offered Rate (LIBOR) | ||
Debt Instrument [Line Items] | ||
Interest rate (percent) | 0.875% |
Long-Term Debt_ Debt Transactio
Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands | Aug. 19, 2016 | Aug. 09, 2016 | Jan. 13, 2016 | Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 07, 2016 | Feb. 12, 2016 |
Debt Instrument [Line Items] | |||||||||
Interest rate swap settlement | $ 28,820 | $ 0 | $ 0 | ||||||
Net proceeds from the offering | $ 546,000 | 1,767,608 | 300,000 | $ 160,000 | |||||
Interest Rate Swap | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest rate swap settlement | $ 29,000 | (29,000) | |||||||
Notional amount | $ 400,000 | 400,000 | |||||||
Senior Unsecured Notes Due 2017 | Source Gas | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest rate (percent) | 5.90% | 5.90% | |||||||
Repayment of debt | $ 325,000 | ||||||||
Senior Secured Notes Due 2019 | Source Gas | |||||||||
Debt Instrument [Line Items] | |||||||||
Interest rate (percent) | 3.98% | 3.98% | |||||||
Repayment of debt | $ 95,000 | ||||||||
Corporate Term Loan Due June 2017 | Source Gas | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayment of debt | 100,000 | $ 240,000 | |||||||
Corporate, Non-Segment | Corporate Term Loan Due August 2019 | |||||||||
Debt Instrument [Line Items] | |||||||||
Proceeds from senior unsecured notes | 500,000 | ||||||||
Debt term | 3 years | ||||||||
Repayment of debt | 100,000 | ||||||||
Corporate, Non-Segment | Corporate Term Loan Due April 2017 | |||||||||
Debt Instrument [Line Items] | |||||||||
Repayment of debt | $ 260,000 | ||||||||
Black Hills Corporation | |||||||||
Debt Instrument [Line Items] | |||||||||
Proceeds from senior unsecured notes | 700,000 | 550,000 | |||||||
Long-term debt | 2,698,406 | 1,324,000 | |||||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 400,000 | $ 400,000 | 0 | ||||||
Interest rate (percent) | 3.15% | 3.15% | |||||||
Debt term | 10 years | 10 years | |||||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046 | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 300,000 | $ 300,000 | 0 | ||||||
Interest rate (percent) | 4.20% | 4.20% | |||||||
Debt term | 30 years | ||||||||
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 24,406 | 0 | $ 29,000 | ||||||
Interest rate (percent) | 2.32% | 2.32% | |||||||
Frequency of periodic payment | quarterly | ||||||||
Periodic payment | $ 1,600 | ||||||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026 | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 300,000 | $ 300,000 | 0 | ||||||
Interest rate (percent) | 3.95% | 3.95% | |||||||
Debt term | 10 years | ||||||||
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019 | |||||||||
Debt Instrument [Line Items] | |||||||||
Long-term debt | $ 250,000 | $ 250,000 | $ 0 | ||||||
Interest rate (percent) | 2.50% | 2.50% | |||||||
Debt term | 3 years |
Long-Term Debt_ Deferred Financ
Long-Term Debt: Deferred Financing Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | $ 21,822 | ||
Amortization expense for deferred financing costs | 3,861 | $ 5,617 | $ 1,641 |
Senior Unsecured Notes Due 2023 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 2,921 | ||
Amortization expense for deferred financing costs | 494 | 494 | 653 |
Senior Unsecured Notes Due 2019 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 763 | ||
Amortization expense for deferred financing costs | 643 | 0 | 0 |
Senior Unsecured Notes Due 2020 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 592 | ||
Amortization expense for deferred financing costs | 167 | 167 | 167 |
Senior Unsecured Notes Due 2026 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 2,318 | ||
Amortization expense for deferred financing costs | 262 | 0 | 0 |
Senior Unsecured Notes Due 2027 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 3,281 | ||
Amortization expense for deferred financing costs | 121 | 0 | 0 |
Senior Unsecured Notes Due 2046 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 3,193 | ||
Amortization expense for deferred financing costs | 37 | 0 | 0 |
Corporate Term Loan Due August 2019 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 287 | ||
Amortization expense for deferred financing costs | 144 | 0 | 0 |
Bridge Term Loan | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 0 | ||
Amortization expense for deferred financing costs | 843 | 4,213 | 0 |
Remarketable Junior Subordinated Notes Due 2028 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 1,449 | ||
Amortization expense for deferred financing costs | 122 | 10 | 0 |
First Mortgage Bonds Due 2044 | South Dakota Electric | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 663 | ||
Amortization expense for deferred financing costs | 24 | 24 | 6 |
First Mortgage Bonds Due 2044 | Wyoming Electric | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 613 | ||
Amortization expense for deferred financing costs | 23 | 22 | 6 |
First Mortgage Bonds Due 2032 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 518 | ||
Amortization expense for deferred financing costs | 33 | 33 | 33 |
First Mortgage Bonds Due 2039 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 1,734 | ||
Amortization expense for deferred financing costs | 76 | 76 | 76 |
First Mortgage Bonds Due 2037 | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 643 | ||
Amortization expense for deferred financing costs | 31 | 31 | 31 |
Deferred Financing Costs, Other | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 506 | ||
Amortization expense for deferred financing costs | 304 | 43 | 53 |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 2,341 | ||
Amortization expense for deferred financing costs | $ 537 | $ 504 | $ 616 |
Long-Term Debt_ Dividend Restri
Long-Term Debt: Dividend Restrictions (Details) $ in Millions | Dec. 31, 2016USD ($) |
Utilities Group | |
Debt Instrument [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 257 |
Notes Payable (Details)
Notes Payable (Details) | Aug. 09, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Jun. 30, 2016USD ($) |
Revolving Credit Facility [Line Items] | |||||
Revolving Credit Facility | $ 96,600,000 | $ 76,800,000 | |||
Commercial Paper [Abstract] | |||||
Commercial Paper | 750,000,000 | ||||
Deferred Finance Costs [Abstract] | |||||
Deferred Financing Costs Remaining on Balance Sheet | 21,822,000 | ||||
Amortization expense for deferred financing costs | 3,861,000 | 5,617,000 | $ 1,641,000 | ||
Revolving Credit Facility | |||||
Revolving Credit Facility [Line Items] | |||||
Revolving Credit Facility | 96,600,000 | 76,800,000 | |||
Current borrowing capacity | $ 750,000,000 | $ 500,000,000 | |||
Number Of One-Year Extension Options | 2 | ||||
Debt term | 1 year | ||||
Maximum Borrowing Capacity | $ 1,000,000,000 | ||||
Commitment Fee Percentage | 0.20% | ||||
Letters of Credit Outstanding | $ 36,000,000 | 33,000,000 | |||
Commercial Paper [Abstract] | |||||
Commercial paper, term | 1 year | ||||
Deferred Finance Costs [Abstract] | |||||
Deferred financing costs | 5,400,000 | ||||
Deferred Financing Costs Remaining on Balance Sheet | 2,341,000 | ||||
Amortization expense for deferred financing costs | $ 537,000 | $ 504,000 | $ 616,000 | ||
Debt Covenants Disclosure [Abstract] | |||||
Consolidated Indebtedness to Capitalization Ratio, Requirement (percent) | 0.70 | ||||
Consolidated Indebtedness to Capitalization Ratio, Actual (percent) | 62.00% | ||||
Revolving Credit Facility | Base Rate Borrowings | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 0.25% | ||||
Revolving Credit Facility | Eurodollar Borrowings | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 1.25% | ||||
Revolving Credit Facility | Letters of Credit | |||||
Revolving Credit Facility [Line Items] | |||||
Interest Rate at Period End | 1.25% | ||||
Commercial Paper | |||||
Revolving Credit Facility [Line Items] | |||||
Debt term | 397 days | ||||
Commercial Paper [Abstract] | |||||
Commercial Paper, Unused Borrowing Capacity, Amount | $ 750,000,000 | ||||
Commercial paper, term | 397 days | ||||
Maximum | |||||
Debt Covenants Disclosure [Abstract] | |||||
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year | 0.65 | ||||
Consolidated Indebtedness to Capitalization Ratio, Requirement (percent) | 0.70 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | $ 44,735 | $ 47,386 |
Liabilities Incurred | 3 | 828 |
Liabilities Settled | (2,154) | (4,693) |
Accretion | 3,186 | 2,560 |
Liabilities Acquired | 22,412 | 0 |
Revisions to Prior Estimates | 1,457 | (1,346) |
Ending Balance | 69,639 | 44,735 |
Electric Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 4,462 | 7,012 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | 0 | (2,733) |
Accretion | 191 | 183 |
Liabilities Acquired | 0 | 0 |
Revisions to Prior Estimates | 8 | 0 |
Ending Balance | 4,661 | 4,462 |
Gas Utilities | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 136 | 291 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | 0 | (168) |
Accretion | 791 | 13 |
Liabilities Acquired | 22,412 | 0 |
Revisions to Prior Estimates | 6,436 | 0 |
Ending Balance | 29,775 | 136 |
Retirement of gas pipelines liability | 22,000 | |
Mining | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | 18,633 | 19,138 |
Liabilities Incurred | 0 | 0 |
Liabilities Settled | (105) | 0 |
Accretion | 822 | 993 |
Liabilities Acquired | 0 | 0 |
Revisions to Prior Estimates | (6,910) | (1,498) |
Ending Balance | $ 12,440 | 18,633 |
Estimated change in equipment costs (percent) | 33.00% | |
Oil and Gas | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning Balance | $ 21,504 | 20,945 |
Liabilities Incurred | 3 | 828 |
Liabilities Settled | (2,049) | (1,792) |
Accretion | 1,382 | 1,371 |
Liabilities Acquired | 0 | 0 |
Revisions to Prior Estimates | 1,923 | 152 |
Ending Balance | $ 22,763 | $ 21,504 |
Risk Management Activities (Det
Risk Management Activities (Details) $ in Thousands | Aug. 19, 2016USD ($) | Aug. 09, 2016 | Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($)MMBTUbbl | Dec. 31, 2015USD ($)MMBTUbbl | Dec. 31, 2014USD ($) |
Derivative [Line Items] | ||||||
Interest rate swap settlement | $ 28,820 | $ 0 | $ 0 | |||
Effective portion of the loss reclassified from AOCI | 28,000 | |||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 1,000 | |||||
Derivative assets, non-current | 222 | 3,441 | ||||
Derivative liabilities, current | 2,459 | 2,835 | ||||
Derivative liabilities, non-current | 274 | 156 | ||||
Oil and Gas | ||||||
Derivative [Line Items] | ||||||
Loss to be reclassified within twelve months | (900) | |||||
Revolving Credit Facility | ||||||
Derivative [Line Items] | ||||||
Debt term | 1 year | |||||
Black Hills Corporation | ||||||
Derivative [Line Items] | ||||||
Long-term debt | 2,698,406 | 1,324,000 | ||||
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2027 | ||||||
Derivative [Line Items] | ||||||
Long-term debt | $ 400,000 | $ 400,000 | 0 | |||
Debt term | 10 years | 10 years | ||||
Cash Flow Hedging | ||||||
Derivative [Line Items] | ||||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | $ (953) | 0 | 0 | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | 7,106 | $ 10,813 | (5,664) | |||
Interest Rate Swap | ||||||
Derivative [Line Items] | ||||||
Notional amount | $ 400,000 | 400,000 | ||||
Interest rate swap settlement | $ 29,000 | (29,000) | ||||
Interest Rate Swap | Designated as Hedging Instrument | ||||||
Derivative [Line Items] | ||||||
Cash flow hedge loss to be reclassified during next 12 months, Net | $ 2,900 | |||||
Interest Rate Swap | Interest Rate Swap One | Designated as Hedging Instrument | ||||||
Derivative [Line Items] | ||||||
Maximum Term | 16 months | |||||
Notional amount | $ 250,000 | |||||
Weighted average fixed interest rate | 2.29% | |||||
Derivative assets, non-current | $ 3,441 | |||||
Derivative liabilities, current | 0 | |||||
Derivative liabilities, non-current | $ 0 | |||||
Interest Rate Swap | Revolving Credit Facility | Designated as Hedging Instrument | ||||||
Derivative [Line Items] | ||||||
Maximum Term | 1 month | 13 months | ||||
Notional amount | $ 50,000 | $ 75,000 | ||||
Weighted average fixed interest rate | 4.94% | 4.97% | ||||
Derivative assets, non-current | $ 0 | $ 0 | ||||
Derivative liabilities, current | 90 | 2,835 | ||||
Derivative liabilities, non-current | 0 | 156 | ||||
Derivative Expired During the Period | 25,000 | |||||
Interest Rate Swap | Cash Flow Hedging | ||||||
Derivative [Line Items] | ||||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | (953) | 0 | 0 | |||
Interest Rate Swap | Cash Flow Hedging | Designated as Hedging Instrument | ||||||
Derivative [Line Items] | ||||||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | $ 3,899 | $ 3,647 | $ 3,669 | |||
Crude Oil | Swaps and Options | Oil and Gas | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | bbl | 108,000 | 198,000 | ||||
MaximumTerm Hedged in Cash Flow Hedge | 24 months | 24 months | ||||
Crude Oil | Options Held | Oil and Gas | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | bbl | 36,000 | |||||
MaximumTerm Hedged in Cash Flow Hedge | 12 months | |||||
Natural Gas | Swap | Oil and Gas | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 2,700,000 | 4,392,500 | ||||
MaximumTerm Hedged in Cash Flow Hedge | 24 months | 24 months | ||||
Natural Gas, Distribution | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 2,133,000 | |||||
Natural Gas, Distribution | Cash Flow Hedging | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 2,138,300 | |||||
Natural Gas, Distribution | Future | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 14,770,000 | 20,580,000 | ||||
Maximum Term | 48 months | 60 months | ||||
Natural Gas, Distribution | Commodity Option | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 3,020,000 | 2,620,000 | ||||
Maximum Term | 5 months | 3 months | ||||
Natural Gas, Distribution | Basis Swap | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 12,250,000 | 18,150,000 | ||||
Maximum Term | 48 months | 60 months | ||||
Natural Gas, Distribution | Fixed for Float Swaps Purchased | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 4,622,302 | 0 | ||||
Maximum Term | 28 months | 0 months | ||||
Natural Gas, Distribution | Purchase Contract | ||||||
Derivative [Line Items] | ||||||
Notional amount - commodities | MMBTU | 21,504,378 | 0 | ||||
Maximum Term | 10 months | 0 months | ||||
External Credit Rating, Non Investment Grade | ||||||
Derivative [Line Items] | ||||||
Non-investment grade credit exposure | $ 1,100 | |||||
Subsequent Event | Interest Rate Swap | Revolving Credit Facility | Designated as Hedging Instrument | ||||||
Derivative [Line Items] | ||||||
Derivative Expired During Subsequent Period | $ 50,000 |
Risk Management Activities_ Hed
Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | $ 1,000 | ||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Regulatory assets | 296,142 | $ 232,484 | |
Gas price derivatives | |||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Regulatory assets | 8,843 | 23,583 | |
Not Designated as Hedging Instrument | |||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Amount of Gain/(Loss) on Derivatives Recognized in Income | 890 | 0 | $ 0 |
Sales Revenue, Net | Not Designated as Hedging Instrument | |||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Amount of Gain/(Loss) on Derivatives Recognized in Income | (50) | 0 | 0 |
Fuel, purchased power and cost of natural gas sold | Not Designated as Hedging Instrument | |||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Amount of Gain/(Loss) on Derivatives Recognized in Income | 940 | 0 | 0 |
Cash Flow Hedging | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | 7,106 | 10,813 | (5,664) |
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | (953) | 0 | 0 |
Cash Flow Hedging | Designated as Hedging Instrument | |||
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Amount of Gain/(Loss) on Derivatives Recognized in Income | (38,901) | 1,857 | 19,809 |
Cash Flow Hedging | Interest Rate Swap | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | (953) | 0 | 0 |
Cash Flow Hedging | Interest Rate Swap | Designated as Hedging Instrument | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | 3,899 | 3,647 | 3,669 |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | (31,222) | 2,888 | (536) |
Cash Flow Hedging | Interest Rate Swap | Interest Expense | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | (3,899) | (3,647) | (3,669) |
Cash Flow Hedging | Commodity derivatives | Designated as Hedging Instrument | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | (11,005) | (14,460) | 1,995 |
Derivative Instruments Not Designated as Hedging Instruments [Abstract] | |||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | (573) | 9,782 | 14,681 |
Cash Flow Hedging | Commodity derivatives | Sales Revenue, Net | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | 11,019 | 14,460 | (1,995) |
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 0 | $ 0 | $ 0 |
Cash Flow Hedging | Commodity derivatives | Fuel, purchased power and cost of natural gas sold | |||
Summary of Cash Flow Hedge Activity [Abstract] | |||
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | (14) | ||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | $ 0 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | $ 4,360 | $ 3,441 |
Derivative, Liabilities, Fair Value Disclosure | 2,733 | 2,991 |
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 | (5,995) | (12,937) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (11,144) | (25,141) |
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 | 10,355 | 16,378 |
Derivative Liabilities, Total | 13,877 | 28,132 |
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 | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Total | 4,360 | 3,441 |
Derivative Liabilities, Total | 2,733 | 2,991 |
Commodity Contract | 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 | (3,262) | (2,293) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | (11,144) | (24,585) |
Commodity Contract | Fair Value, Measurements, Recurring | Oil and Gas | ||
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 | (2,733) | (10,644) |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | (556) |
Commodity Contract | Fair Value, Measurements, Recurring | 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 |
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Oil and Gas | ||
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 |
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 7,469 | 2,293 |
Derivative, Liabilities, Fair Value Disclosure | 12,201 | 24,585 |
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Oil and Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 2,886 | 10,644 |
Derivative, Liabilities, Fair Value Disclosure | 1,586 | 556 |
Commodity Contract | Fair Value, Measurements, Recurring | 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 |
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Oil and Gas | ||
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 |
Commodity Contract | Fair Value | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 4,207 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 1,057 | 0 |
Commodity Contract | Fair Value | Fair Value, Measurements, Recurring | Oil and Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 153 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 1,586 | 0 |
Interest Rate Swap | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 3,441 |
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 90 | 2,991 |
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset | 0 | 0 |
Interest Rate Swap | Fair Value, Measurements, Recurring | 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 |
Interest Rate Swap | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Fair Value Disclosure | 0 | 3,441 |
Derivative, Liabilities, Fair Value Disclosure | 90 | 2,991 |
Interest Rate Swap | Fair Value, Measurements, Recurring | 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) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 10,355 | $ 16,378 |
Derivative Liability, Fair Value, Gross Liability | 13,877 | 28,132 |
Designated as Hedging Instrument | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 1,285 | 14,085 |
Derivative Liability, Fair Value, Net | 1,418 | 3,547 |
Derivatives Not Designated as Hedge Instruments | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 3,075 | 0 |
Derivative Liability, Fair Value, Net | 1,315 | 22,292 |
Commodity derivatives | Designated as Hedging Instrument | Derivative Assets, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1,161 | 9,981 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Commodity derivatives | Designated as Hedging Instrument | Derivative Assets, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 124 | 663 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Commodity derivatives | Designated as Hedging Instrument | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 1,090 | 465 |
Commodity derivatives | Designated as Hedging Instrument | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 238 | 91 |
Commodity derivatives | Derivatives Not Designated as Hedge Instruments | Derivative Assets, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 2,977 | 0 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Commodity derivatives | Derivatives Not Designated as Hedge Instruments | Derivative Assets, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 98 | 0 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Commodity derivatives | Derivatives Not Designated as Hedge Instruments | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 1,279 | 9,586 |
Commodity derivatives | Derivatives Not Designated as Hedge Instruments | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 36 | 12,706 |
Interest Rate Swap | Designated as Hedging Instrument | Derivative Assets, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 3,441 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Interest Rate Swap | Designated as Hedging Instrument | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 90 | 2,835 |
Interest Rate Swap | Designated as Hedging Instrument | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 0 | 156 |
Interest Rate Swap | Derivatives Not Designated as Hedge Instruments | Derivative Liabilities, Current | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | 0 | 0 |
Interest Rate Swap | Derivatives Not Designated as Hedge Instruments | Derivative Liabilities, Noncurrent | ||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | $ 0 | $ 0 |
Fair Value Measurements_ Bala85
Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | $ 10,355 | $ 16,378 |
Gross Amounts Offset In Statement Of Financial Position Assets | (5,995) | (12,937) |
Derivative Asset | 4,360 | 3,441 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 13,877 | 28,132 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (11,144) | (25,141) |
Derivative Liability | 2,733 | 2,991 |
Contract Subject to Master Netting Arrangement | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 7,155 | 16,378 |
Gross Amounts Offset In Statement Of Financial Position Assets | (5,995) | (12,937) |
Derivative Asset | 1,160 | 3,441 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 12,730 | 28,132 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (11,144) | (25,141) |
Derivative Liability | 1,586 | 2,991 |
Contract Subject to Master Netting Arrangement | Interest Rate Swap | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 3,441 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 0 | 3,441 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | 2,991 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | 0 |
Derivative Liability | 0 | 2,991 |
Contract Not Subject to Master Netting Arrangement | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 3,200 | 0 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 3,200 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1,147 | 0 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | 0 |
Derivative Liability | 1,147 | 0 |
Contract Not Subject to Master Netting Arrangement | Interest Rate Swap | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 0 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 90 | 0 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | 0 |
Derivative Liability | 90 | 0 |
Crude Oil | Contract Subject to Master Netting Arrangement | Basis Swap | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 2,886 | 10,644 |
Gross Amounts Offset In Statement Of Financial Position Assets | (2,733) | (10,644) |
Derivative Asset | 153 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1,586 | |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | |
Derivative Liability | 1,586 | |
Crude Oil | Contract Not Subject to Master Netting Arrangement | Basis Swap | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 0 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | |
Derivative Liability | 0 | |
Natural Gas, Distribution | Contract Subject to Master Netting Arrangement | Purchase Contract | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 4,269 | 2,293 |
Gross Amounts Offset In Statement Of Financial Position Assets | (3,262) | (2,293) |
Derivative Asset | 1,007 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 11,144 | 24,585 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (11,144) | (24,585) |
Derivative Liability | 0 | 0 |
Natural Gas, Distribution | Contract Not Subject to Master Netting Arrangement | Purchase Contract | ||
Derivative Asset [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | 3,200 | 0 |
Gross Amounts Offset In Statement Of Financial Position Assets | 0 | 0 |
Derivative Asset | 3,200 | 0 |
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 1,057 | 0 |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | 0 |
Derivative Liability | $ 1,057 | 0 |
Natural Gas | Contract Subject to Master Netting Arrangement | Basis Swap | ||
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 556 | |
Gross Amounts Offset In Statement Of Financial Position Liabilities | (556) | |
Derivative Liability | 0 | |
Natural Gas | Contract Not Subject to Master Netting Arrangement | Basis Swap | ||
Derivative Liability [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 0 | |
Gross Amounts Offset In Statement Of Financial Position Liabilities | 0 | |
Derivative Liability | $ 0 |
Fair Value of Financial Instr86
Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | $ 13,580 | $ 440,861 |
Restricted cash - carrying amount | 2,274 | 1,697 |
Notes payable | 96,600 | 76,800 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | 13,580 | 440,861 |
Restricted cash - carrying amount | 2,274 | 1,697 |
Notes payable | 96,600 | 76,800 |
Long-term debt, including current maturities - carrying amount | 3,216,932 | 1,853,682 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - fair value | 13,580 | 440,861 |
Restricted Cash - fair value | 2,274 | 1,697 |
Notes payable - fair value | 96,600 | 76,800 |
Long-term debt, including current maturities - fair value | $ 3,351,305 | $ 1,992,274 |
Equity Units (Details)
Equity Units (Details) $ / shares in Units, shares in Thousands | Nov. 23, 2015USD ($)shares$ / shares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Debt Instrument [Line Items] | ||||
Proceeds from Sale of Interest in Corporate Unit | $ 299,000,000 | |||
Equity Unit Stated Amount (usd per share) | $ / shares | $ 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 | |||
Debt Instrument, Convertible, Reference Price (usd per share) | $ / shares | $ 40.25 | |||
Stock Purchase Contract Rate | 4.25% | |||
Equity Unit, Annual Dividend Amount (usd per share) | $ / shares | $ 2.125 | |||
Premium on Publicly-Traded Equity Units Known As Corporate Units | $ 33,000,000 | $ 33,118,000 | ||
Equity units - issuance | 290,030,000 | $ 0 | 290,030,000 | $ 0 |
Stock Purchase Contract Liability | $ 23,335,000 | |||
Black Hills Corporation | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ 2,698,406,000 | 1,324,000,000 | ||
Minimum | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Convertible, Conversion Ratio | 1.0572 | |||
Maximum | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Convertible, Conversion Ratio | 1.2422 | |||
Remarketable Junior Subordinated Notes Due 2028 | ||||
Debt Instrument [Line Items] | ||||
Issuance of equity units | shares | 5,980 | |||
Debt Instrument, Convertible, Conversion Price (usd per share) | $ / shares | $ 47.2938 | |||
Remarketable Junior Subordinated Notes Due 2028 | Black Hills Corporation | ||||
Debt Instrument [Line Items] | ||||
RSN Interest Rate (percent) | 3.50% | 3.50% | ||
Long-term debt | $ 299,000,000 | $ 299,000,000 | $ 299,000,000 |
Equity_ At-the-Market Equity Of
Equity: At-the-Market Equity Offering Program (Details) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2016USD ($)shares | Dec. 31, 2016USD ($)shares | |
At The Market Equity Offering Program Authorized Aggregate Value | $ 200 | $ 200 |
Common Stock | ||
At The Market Equity Offering Program Shares Issued | shares | 218,647 | 1,968,738 |
At The Market Equity Program Proceeds from Sale of Stock | $ 13 | $ 119 |
Payments of Stock Issuance Costs | $ 0.1 | $ 1.2 |
Equity_ Common Stock Offering (
Equity: Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Thousands | Nov. 23, 2015 | Dec. 31, 2016 | Dec. 31, 2015 |
Class of Stock [Line Items] | |||
Issuance of common stock | $ 119,990 | $ 254,581 | |
Common Stock | |||
Class of Stock [Line Items] | |||
Issuance of common stock, shares | 6,325,000 | 1,968,738 | 6,325,000 |
Shares issued, price (usd per share) | $ 40.25 | ||
Issuance of common stock | $ 246,000 | $ 1,969 | $ 6,325 |
Equity_ Equity Compensation Pla
Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stockholders' Equity Note [Abstract] | |||
Shares available for grant | 1,115,557 | ||
Unrecognized compensation expense | $ 13,500 | ||
Weighted-average recognition period | 2 years | ||
Stock-based compensation expense | $ 10,885 | $ 4,076 | $ 9,329 |
Equity_ Stock Options (Details)
Equity: Stock Options (Details) | Dec. 31, 2016shares |
Employee Stock Option | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Exercisable at end of period | 119,415 |
Equity_ Restricted Stock (Detai
Equity: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value | |||
Unrecognized compensation expense | $ 13,500 | ||
Weighted-average recognition period | 2 years | ||
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 | 202 | ||
Granted | 195 | ||
Vested | (88) | ||
Forfeited | (14) | ||
Restricted Stock at end of period | 295 | 202 | |
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) | $ 48.96 | ||
Granted (usd per share) | 53.55 | $ 50.01 | $ 54.34 |
Vested (usd per share) | 48 | ||
Forfeited (usd per share) | 51.89 | ||
Balance at end of period (usd per share) | $ 52.15 | $ 48.96 | |
Restricted Stock and RSUs, total fair value of shares vested | $ 4,602 | $ 6,009 | $ 6,114 |
Unrecognized compensation expense | $ 10,300 | ||
Weighted-average recognition period | 2 years 1 month |
Equity_ Performance Share Plan
Equity: Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation expense | $ 13,500,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Weighted-average recognition period | 2 years | ||
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% | ||
Performance Share Award, Payout, Change Of Control | 100.00% | ||
Unrecognized compensation expense | $ 2,300,000 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 43 | 44 | |
Performance Shares, Number of Shares Authorized, End of Period | 53 | 43 | 44 |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Granted (usd per share) | $ 54.92 | $ 55.18 | |
Blended volatility | 24.00% | 21.00% | 23.00% |
Historical volatility | 50.00% | ||
Implied volatility | 50.00% | ||
Performance Shares Issued During Period, Shares, Treasury Stock Reissued | 0 | 69 | 59 |
Performance Shares, Total Share-based Liabilities Paid | $ 0 | $ 3,657,000 | $ 3,011,000 |
Performance Shares, Vested in Period, Total Intrinsic Value | 0 | $ 7,314,000 | $ 6,020,000 |
Target shares, value | 0 | ||
Unrecognized compensation expense | $ 3,100,000 | ||
Weighted-average recognition period | 1 year 9 months | ||
Performance Shares, Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 74 | ||
Performance Shares, Granted in Period | 27 | ||
Performance Shares, Forfeited in Period | 0 | ||
Performance Shares, Vested in Period | (30) | ||
Performance Shares, Number of Shares Authorized, End of Period | 71 | 74 | |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Balance at beginning of period (usd per share) | $ 47.21 | ||
Granted (usd per share) | 47.76 | ||
Forfeited (usd per share) | 0 | ||
Vested (usd per share) | 35.86 | ||
Balance at end of period (usd per share) | $ 52.29 | $ 47.21 | |
Performance Shares, Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward] | |||
Performance Shares, Number of Shares Authorized, Beginning of Period | 74 | ||
Performance Shares, Granted in Period | 27 | ||
Performance Shares, Forfeited in Period | 0 | ||
Performance Shares, Vested in Period | (30) | ||
Performance Shares, Number of Shares Authorized, End of Period | 71 | 74 | |
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward] | |||
Balance at end of period (usd per share) | $ 48.05 | ||
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) - Dividend Reinvestment Plan - $ / shares shares in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Class of Stock [Line Items] | ||
Percent of recent average market price | 100.00% | |
Shares Issued | 51 | 66 |
Weighted Average Price (usd per share) | $ 58.24 | $ 44.79 |
Unissued Shares Available | 356 | 408 |
Equity_ Preferred Stock (Detail
Equity: Preferred Stock (Details) | Dec. 31, 2016shares |
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) - USD ($) $ in Thousands | Apr. 14, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Proceeds from Noncontrolling Interests | $ 216,370 | $ 0 | $ 0 | |
Net income attributable to noncontrolling interest | (9,661) | 0 | 0 | |
Assets, Current | 466,814 | 806,477 | ||
Property, Plant and Equipment, Gross | 6,412,223 | 4,976,778 | ||
Liabilities, Current | 527,932 | 406,355 | ||
Power Generation | ||||
Net income attributable to noncontrolling interest | (9,559) | 0 | $ 0 | |
Property, Plant and Equipment, Gross | 162,728 | 158,903 | ||
Variable Interest Entity, Primary Beneficiary | ||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||
Proceeds from Noncontrolling Interests | $ 216,000 | |||
Assets, Current | 12,627 | 0 | ||
Property, Plant and Equipment, Gross | 218,798 | 0 | ||
Liabilities, Current | $ 4,342 | $ 0 |
Impairment of Assets (Details)
Impairment of Assets (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)$ / bbl$ / MMcf | Dec. 31, 2015USD ($)$ / bbl$ / MMcf | Dec. 31, 2014USD ($)$ / bbl$ / MMcf | |
Impaired Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | $ 106,957 | $ 249,608 | $ 0 |
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 | 2.59 | 4.35 |
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 | 1.27 | 3.33 |
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 | 50.28 | 94.99 |
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 | 44.72 | 85.80 |
Property, Plant and Equipment, Net | $ 4,468,989 | $ 3,259,094 | |
Oil and Gas | |||
Impaired Assets Held and Used [Line Items] | |||
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 | 2.59 | |
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 | 1.27 | |
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 | 50.28 | |
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 | 44.72 | |
Property, Plant and Equipment, Net | $ 84,880 | $ 206,868 | |
Oil and Gas | Impairment Based On Ceiling Value Of Assets | |||
Impaired Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 92,000 | $ 250,000 | |
Oil and Gas | Assets Not Expected To Be Utilized In Cost Of Service Gas Program | |||
Impaired Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 14,000 | ||
Property, Plant and Equipment, Net | $ 23,000 |
Impairment Of Assets_ Equity In
Impairment Of Assets: Equity Investments In Unconsolidated Subsidiaries (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Equity Method Investment, Other than Temporary Impairment | $ 0 | $ 4,405 | $ 0 |
Oil and Gas | |||
Equity Method Investment, Other than Temporary Impairment | $ 4,405 | ||
Willow Creek / Lodge Creek Pipeline And Gathering System | Oil and Gas | |||
Equity Method Investment, Ownership Percentage | 25.00% | ||
Equity Method Investment, Other than Temporary Impairment | $ 5,200 | ||
Equity Method Investment, Ownership Percentage Sold | 25.00% |
Operating Lease (Details)
Operating Lease (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Leases, Rent Expense, Net [Abstract] | |||
Rent expense | $ 9,568 | $ 7,177 | $ 6,932 |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2,017 | 6,739 | ||
2,018 | 5,564 | ||
2,019 | 4,441 | ||
2,020 | 2,639 | ||
2,021 | 1,652 | ||
Thereafter | $ 6,245 |
Income Taxes_ Current and Defer
Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current: | |||
Federal | $ (23,820) | $ 2,549 | $ (2,319) |
State | (1,922) | 1,319 | (1,288) |
Total Current | (25,742) | 3,868 | (3,607) |
Deferred: | |||
Federal | 36,012 | (23,592) | 64,780 |
State | 257 | (2,323) | 5,658 |
Tax credit amortization | (52) | (113) | (206) |
Total Deferred | 36,217 | (26,028) | 70,232 |
Total Current and Deferred | $ 10,475 | $ (22,160) | $ 66,625 |
Income Taxes_ Deferred Income T
Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
Deferred Tax Assets, Net [Abstract] | ||
Regulatory liabilities | $ 43,586 | $ 58,200 |
Employee benefits | 26,400 | 29,638 |
Federal net operating loss | 217,922 | 252,780 |
Other deferred tax assets | 85,907 | 83,485 |
Less: Valuation allowance | (4,304) | (9,263) |
Total deferred tax assets | 369,511 | 414,840 |
Deferred tax liabilities: | ||
Accelerated depreciation, amortization and other plant-related differences | (711,293) | (820,111) |
Regulatory assets | (29,092) | (49,471) |
State deferred tax liability | (35,065) | (47,987) |
Deferred costs | (26,121) | (18,551) |
Other deferred tax liabilities | (18,519) | (14,326) |
Total deferred tax liabilities | (820,090) | (950,446) |
Net deferred tax liability | 450,579 | $ 535,606 |
Deferred Tax Asset - Asset Impairment | ||
Prior Period Reclassification Adjustment | 182,000 | |
Deferred Tax Liability - Mining Development And Oil Exploration | ||
Prior Period Reclassification Adjustment | $ 184,000 |
Income Taxes_ Effective Tax Rat
Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details) | Apr. 14, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Income Tax Disclosure [Abstract] | ||||
Federal Statutory Rate | 35.00% | 35.00% | 35.00% | |
State income tax (net of federal tax effect) | 0.20% | 1.00% | 1.10% | |
Amortization of excess deferred income taxes and investment tax credits | (0.10%) | 0.20% | (0.10%) | |
Percentage depletion | (8.20%) | 3.50% | (1.00%) | |
Non-controlling interest | (3.60%) | (0.00%) | (0.00%) | |
Equity AFUDC | (1.10%) | 0.30% | (0.10%) | |
Tax credits | (1.50%) | 0.50% | (0.10%) | |
Transaction costs | 1.10% | 0.00% | 0.00% | |
Accounting for uncertain tax positions adjustment | (6.00%) | (3.50%) | (0.10%) | |
Flow-through adjustments | (5.10%) | 3.80% | (0.90%) | |
Other tax differences | 0.60% | 0.00% | (0.10%) | |
Effective Income Tax Rate, Continuing Operations | 11.30% | 40.80% | 33.70% | |
Variable Interest Entity, Primary Beneficiary | ||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% |
Income Taxes_ Net Operating Los
Income Taxes: Net Operating Loss Carryforwards (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Internal Revenue Service (IRS) | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards | $ 721,075 |
Internal Revenue Service (IRS) | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Expiration Dates | Dec. 31, 2019 |
Internal Revenue Service (IRS) | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Expiration Dates | Dec. 31, 2036 |
State and Local Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards | $ 616,524 |
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards Valuation Allowance | 900 |
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 100 |
State and Local Jurisdiction | Minimum | |
Operating Loss Carryforwards [Line Items] | |
Expiration Dates | Dec. 31, 2017 |
State and Local Jurisdiction | Maximum | |
Operating Loss Carryforwards [Line Items] | |
Expiration Dates | Dec. 31, 2036 |
Income Taxes_ Reconciliation of
Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Liability for Uncertain Tax Positions, Noncurrent, Period Start | $ 31,986 | $ 32,192 | $ 37,631 |
Additions for prior year tax positions | 2,423 | 3,285 | 1,253 |
Reductions for prior year tax positions | (19,174) | (3,491) | (6,692) |
Additions for current year tax positions | 0 | 0 | 0 |
Settlements | (11,643) | 0 | 0 |
Liability for Uncertain Tax Positions, Noncurrent, Period End | 3,592 | $ 31,986 | $ 32,192 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | $ 700 |
Income Taxes_ Interest, Penalti
Income Taxes: Interest, Penalties and Audits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Examination [Line Items] | |||
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense | $ 0 | $ 1,800 | $ 1,600 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 13,300 | ||
Deferred Income Tax Expense (Benefit) | 36,217 | (26,028) | 70,232 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 11,643 | $ 0 | $ 0 |
Like-Kind Exchange, Aquila and IPP Transactions | |||
Income Tax Examination [Line Items] | |||
Deferred Income Tax Expense (Benefit) | 125,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 29,000 | ||
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Accumulated Deferred Income Taxes | 17,000 | ||
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Current Taxes Payable | $ 12,000 |
Income Taxes_ Carryforwards, St
Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Tax Credit Carryforward [Line Items] | |||
Income Tax Expense (Benefit) | $ 10,475 | $ (22,160) | $ 66,625 |
Maximum | Foreign Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Expiration Date | Dec. 31, 2017 | ||
Foreign Tax Authority | |||
Tax Credit Carryforward [Line Items] | |||
Other Tax Carryforward, Gross Amount | $ 2,300 | ||
Tax Credit Carryforward, Valuation Allowance | 1,700 | $ 500 | |
Internal Revenue Service (IRS) | Settlement with Taxing Authority | |||
Tax Credit Carryforward [Line Items] | |||
Other Tax Carryforward, Gross Amount | 1,800 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 1,200 | ||
Income Tax Expense (Benefit) | 600 | ||
State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Valuation Allowance | 6,600 | ||
State and Local Jurisdiction | Investment Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | 19,765 | ||
State and Local Jurisdiction | Research Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Deferred Tax Assets, State Tax Credits | 167 | ||
State and Local Jurisdiction | Deferred Tax Asset [Domain] | |||
Tax Credit Carryforward [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 3,600 | ||
Income Tax Expense (Benefit) | 1,900 | ||
State and Local Jurisdiction | Deferred Tax Asset [Domain] | Utilities Group | |||
Tax Credit Carryforward [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 1,700 | ||
State and Local Jurisdiction | Minimum | Investment Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Expiration Date | Dec. 31, 2023 | ||
State and Local Jurisdiction | Maximum | Investment Tax Credit Carryforward | |||
Tax Credit Carryforward [Line Items] | |||
Tax Credit Carryforward, Expiration Date | Dec. 31, 2036 | ||
Valuation Allowance, Operating Loss Carryforwards | State and Local Jurisdiction | |||
Tax Credit Carryforward [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 100 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Interest expense | $ 139,590 | $ 86,278 | $ 73,017 | ||||||||
Revenue | $ 463,788 | $ 333,786 | $ 325,441 | $ 449,959 | $ 318,259 | $ 272,105 | $ 272,254 | $ 441,987 | 1,572,974 | 1,304,605 | 1,393,570 |
Fuel, purchased power and cost of natural gas sold | 499,132 | 456,887 | 581,782 | ||||||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 93,106 | (49,522) | 197,515 | ||||||||
Income tax benefit (expense) | (10,475) | 22,160 | (66,625) | ||||||||
Net income (loss) | 82,631 | (32,111) | $ 130,889 | ||||||||
Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Net income (loss) | 3,180 | 4,842 | |||||||||
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | 7,106 | 10,813 | |||||||||
Income tax benefit (expense) | (2,702) | (4,271) | |||||||||
Net income (loss) | 4,404 | 6,542 | |||||||||
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Contract | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Interest expense | (3,899) | (3,647) | |||||||||
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Revenue | 11,019 | 14,460 | |||||||||
Fuel, purchased power and cost of natural gas sold | (14) | 0 | |||||||||
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) | Reclassification out of Accumulated Other Comprehensive Income | |||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||||||||||
Operations and maintenance | 221 | 238 | |||||||||
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] | |||||||||||
Operations and maintenance | (1,978) | (2,822) | |||||||||
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 (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes | (1,757) | (2,584) | |||||||||
Income tax benefit (expense) | 533 | 884 | |||||||||
Net income (loss) | $ (1,224) | $ (1,700) |
Other Comprehensive Income_ Acc
Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | $ (9,055) | $ (15,044) |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (34,883) | (9,055) |
Accumulated Defined Benefit Plans Adjustment | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (15,780) | (20,137) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (1,985) | 2,657 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (16,541) | (15,780) |
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 1,224 | 1,700 |
Accumulated Other Comprehensive Income (Loss) | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (22,648) | 10,831 |
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (3,180) | (4,842) |
Interest Rate Swap | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | (341) | (4,930) |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (20,302) | 2,290 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (18,109) | (341) |
Interest Rate Swap | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 2,534 | 2,299 |
Commodity Contract | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start | 7,066 | 10,023 |
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax | (361) | 5,884 |
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End | (233) | 7,066 |
Commodity Contract | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income | ||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | ||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | $ (6,938) | $ (8,841) |
Supplemental Cash Flow Infor109
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Non-cash investing activities and financing from continuing operations - | |||
Property, plant and equipment acquired with accrued liabilities | $ 29,082 | $ 40,250 | $ 52,584 |
Increase (decrease) in capitalized assets associated with asset retirement obligations | 8,577 | (518) | (5,634) |
Cash (paid) refunded during the period for continuing operations- | |||
Interest (net of amount capitalized) | (112,925) | (77,810) | (69,239) |
Income taxes, net | $ (1,156) | $ (1,202) | $ (413) |
Employee Benefit Plans_ Narrati
Employee Benefit Plans: Narrative (Details) - USD ($) $ in Thousands | Feb. 12, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Maximum Annual Contribution Per Employee, Percent | 50.00% | |||
Employers Matching Contribution, Annual Vesting Percentage | 20.00% | |||
Employee Vesting Period | 5 years | |||
Defined Benefit Plan, Target Plan Asset Allocations | 100.00% | 100.00% | ||
Equity Securities | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 28.00% | 26.00% | ||
Fixed Income Funds | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 57.00% | 59.00% | ||
Maximum | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Employers Matching Contribution, Annual Vesting Percentage | 100.00% | |||
Pension Plans, Defined Benefit | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation | $ 22,187 | $ 75,254 | $ 0 | |
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.87% | 6.75% | 6.75% | |
Pension Plans, Defined Benefit | Minimum | Equity Securities | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 40.00% | |||
Pension Plans, Defined Benefit | Minimum | Fixed Income Funds | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 50.00% | |||
Pension Plans, Defined Benefit | Maximum | Equity Securities | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 50.00% | |||
Pension Plans, Defined Benefit | Maximum | Fixed Income Funds | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 60.00% | |||
Other Postretirement Benefit Plans, Defined Benefit | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation | $ 11,751 | $ 15,091 | $ 0 | |
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 3.83% | 3.00% | 2.00% | |
Other Postretirement Benefit Plans, Defined Benefit | Minimum | Equity Securities | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 30.00% | |||
Other Postretirement Benefit Plans, Defined Benefit | Minimum | Fixed Income Funds | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 60.00% | |||
Other Postretirement Benefit Plans, Defined Benefit | Maximum | Equity Securities | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 40.00% | |||
Other Postretirement Benefit Plans, Defined Benefit | Maximum | Fixed Income Funds | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Target Plan Asset Allocations | 70.00% | |||
Black Hills Corporation | Pension Plans, Defined Benefit | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.75% | 6.75% | ||
Black Hills Utility Holding, Inc. Plan | Pension Plans, Defined Benefit | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 6.75% | 6.75% | ||
SourceGas Retirement Plan | Pension Plans, Defined Benefit | ||||
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract] | ||||
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets | 7.50% | 0.00% |
Employee Benefit Plans_ Target
Employee Benefit Plans: Target Plan Assets Allocation (Details) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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 | 28.00% | 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 | 5.00% | 5.00% |
Fixed Income Funds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Target Allocation Percentage of Assets | 57.00% | 59.00% |
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 | 2.00% | 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 | 8.00% | 9.00% |
Employee Benefit Plans_ Plan Co
Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year | $ 10,000 | |
Pension Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and Other Postretirement Benefit Contributions | 14,200 | $ 10,200 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and Other Postretirement Benefit Contributions | 4,965 | 3,771 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and Other Postretirement Benefit Contributions | 1,565 | 1,564 |
Defined Contribution Plan, Company Retirement | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Employer Contributions | 9,632 | 5,564 |
Defined Contribution Plan, 401K | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Defined Benefit Plan, Employer Contributions | $ 9,645 | $ 9,616 |
Employee Benefit Plans_ Employe
Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 364,695 | $ 288,622 | $ 299,533 |
Pension Plans, Defined Benefit | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 319,816 | 251,733 | |
Pension Plans, Defined Benefit | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | AXA Equitable General Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,325 | 1,072 | |
Pension Plans, Defined Benefit | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,325 | 1,072 | |
Pension Plans, Defined Benefit | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
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, Fair Value of Plan Assets | 5,307 | 1,556 | |
Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 5,307 | 1,556 | |
Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 101,020 | 74,885 | |
Pension Plans, Defined Benefit | Common Collective Trust - Equity | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Common Collective Trust - Equity | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 101,020 | 74,885 | |
Pension Plans, Defined Benefit | Common Collective Trust - Equity | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
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, Fair Value of Plan Assets | 209,815 | 172,016 | |
Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 209,815 | 172,016 | |
Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
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, Fair Value of Plan Assets | 17,912 | 13,347 | |
Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,349 | 2,204 | |
Pension Plans, Defined Benefit | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 29,316 | 25,746 | |
Pension Plans, Defined Benefit | Hedge Funds | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Hedge Funds | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit | Hedge Funds | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 8,470 | 4,681 | $ 4,705 |
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,265 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 7,205 | 4,681 | |
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
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, Fair Value of Plan Assets | 111 | ||
Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 111 | ||
Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,154 | ||
Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 1,154 | ||
Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Postretirement Benefit Plans, Defined Benefit | Equity Securities | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,732 | 4,681 | |
Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,732 | 4,681 | |
Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
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, Fair Value of Plan Assets | 2,473 | ||
Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | Fair Value, Inputs, Level 1 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | Fair Value, Inputs, Level 2 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,473 | ||
Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond | Fair Value, Inputs, Level 3 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Net Asset Value | Pension Plans, Defined Benefit | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 44,879 | 36,889 | |
Net Asset Value | Pension Plans, Defined Benefit | AXA Equitable General Fixed Income | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Net Asset Value | 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, Fair Value of Plan Assets | 0 | 0 | |
Net Asset Value | Pension Plans, Defined Benefit | Common Collective Trust - Equity | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Net Asset Value | 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, Fair Value of Plan Assets | 0 | 0 | |
Net Asset Value | 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, Fair Value of Plan Assets | 15,563 | 11,143 | |
Net Asset Value | Pension Plans, Defined Benefit | Hedge Funds | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 29,316 | $ 25,746 |
Employee Benefit Plans_ Changes
Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands | Feb. 12, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Pension Plans, Defined Benefit | ||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||
Projected benefit obligation at beginning of year | $ 356,575 | $ 377,772 | ||
Transfer from SourceGas Acquisition | $ 22,187 | 75,254 | 0 | |
Service cost | 7,619 | 6,093 | $ 5,448 | |
Interest cost | 15,743 | 15,522 | 15,852 | |
Actuarial (gain) loss | 7,001 | (28,229) | ||
Amendments | 0 | 0 | ||
Benefits Paid | (22,013) | (14,583) | ||
Medicare Part D accrued | 0 | 0 | ||
Plan participants’ contributions | 0 | 0 | ||
Projected benefit obligation at end of year | 440,179 | 356,575 | 377,772 | |
Supplemental Employee Retirement Plans, Defined Benefit | ||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||
Projected benefit obligation at beginning of year | 40,219 | 41,211 | ||
Transfer from SourceGas Acquisition | 0 | 0 | ||
Service cost | 2,099 | 1,300 | ||
Interest cost | 1,257 | 1,455 | ||
Actuarial (gain) loss | 2,049 | (2,072) | ||
Amendments | 0 | 0 | ||
Benefits Paid | (1,755) | (1,675) | ||
Medicare Part D accrued | 0 | 0 | ||
Plan participants’ contributions | 0 | 0 | ||
Projected benefit obligation at end of year | 43,869 | 40,219 | 41,211 | |
Other Postretirement Benefit Plans, Defined Benefit | ||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||
Projected benefit obligation at beginning of year | 48,077 | 49,042 | ||
Transfer from SourceGas Acquisition | $ 11,751 | 15,091 | 0 | |
Service cost | 1,757 | 1,808 | 1,700 | |
Interest cost | 1,942 | 1,801 | 1,919 | |
Actuarial (gain) loss | 2,808 | (1,206) | ||
Amendments | 2,203 | 0 | ||
Benefits Paid | (4,965) | (3,771) | ||
Medicare Part D accrued | 0 | (178) | ||
Plan participants’ contributions | 1,110 | 581 | ||
Projected benefit obligation at end of year | $ 68,023 | $ 48,077 | $ 49,042 |
Employee Benefit Plans_ Chan115
Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning fair value of plan assets | $ 288,622 | $ 299,533 |
Transfer from SourceGas Acquisition | 53,067 | 0 |
Investment income (loss) | 30,819 | (6,528) |
Employer contributions | 14,200 | 10,200 |
Retiree contributions | 0 | 0 |
Benefits paid | (22,013) | (14,583) |
Plan administrative expenses | 0 | 0 |
Ending fair value of plan assets | 364,695 | 288,622 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Retiree contributions | 0 | 0 |
Benefits paid | (1,755) | (1,675) |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning fair value of plan assets | 4,681 | 4,705 |
Transfer from SourceGas Acquisition | 3,340 | 0 |
Investment income (loss) | 256 | (9) |
Employer contributions | 4,048 | 3,175 |
Retiree contributions | 1,110 | 581 |
Benefits paid | (4,965) | (3,771) |
Plan administrative expenses | 0 | 0 |
Ending fair value of plan assets | $ 8,470 | $ 4,681 |
Employee Benefit Plans_ Amounts
Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | $ 296,142 | $ 232,484 |
Non-current liabilities | 173,682 | 146,459 |
Regulatory liabilities | 206,756 | 153,041 |
Pension Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Regulatory assets | 66,640 | 68,915 |
Current liabilities | 0 | 0 |
Non-current assets | 0 | 0 |
Non-current liabilities | 75,484 | 67,953 |
Regulatory liabilities | 5,195 | 0 |
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 | 1,583 | 1,568 |
Non-current assets | 0 | 0 |
Non-current liabilities | 42,286 | 38,651 |
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 | 11,401 | 6,464 |
Current liabilities | 4,360 | 3,543 |
Non-current assets | 21 | 23 |
Non-current liabilities | 55,214 | 39,855 |
Regulatory liabilities | $ 3,419 | $ 3,209 |
Employee Benefit Plans_ Accumul
Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Pension Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 416,786 | $ 334,923 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | 32,090 | 30,558 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 68,023 | $ 48,077 |
Employee Benefit Plans_ Compone
Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | $ 7,619 | $ 6,093 | $ 5,448 |
Interest cost | 15,743 | 15,522 | 15,852 |
Expected return on assets | (23,062) | (19,470) | (18,065) |
Net amortization of prior service cost | 58 | 58 | 62 |
Recognized net actuarial loss (gain) | 7,173 | 11,037 | 4,806 |
Settlement Expense | (10) | 0 | 0 |
Net periodic benefit expense | 7,541 | 13,240 | 8,103 |
Supplemental Non-qualified Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 1,335 | 1,380 | 1,498 |
Interest cost | 1,257 | 1,455 | 1,447 |
Expected return on assets | 0 | 0 | 0 |
Net amortization of prior service cost | 2 | 2 | 2 |
Recognized net actuarial loss (gain) | 829 | 1,081 | 498 |
Settlement Expense | 0 | 0 | 0 |
Net periodic benefit expense | 3,423 | 3,918 | 3,445 |
Other Postretirement Benefit Plans, Defined Benefit | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost | 1,757 | 1,808 | 1,700 |
Interest cost | 1,942 | 1,801 | 1,919 |
Expected return on assets | (279) | (131) | (85) |
Net amortization of prior service cost | (428) | (428) | (428) |
Recognized net actuarial loss (gain) | 335 | 408 | 160 |
Settlement Expense | 0 | 0 | 0 |
Net periodic benefit expense | $ 3,327 | $ 3,458 | $ 3,266 |
Employee Benefit Plans_ Accu119
Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plans, Defined Benefit | ||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract] | ||
Net (gain) loss | $ 8,472 | $ 8,777 |
Prior service cost (gain) | 31 | 41 |
Total AOCI | 8,503 | 8,818 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 2,604 | |
Prior service cost (credit) | 38 | |
Total net periodic benefit cost expected to be recognized during calendar year 2017 | 2,642 | |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract] | ||
Net (gain) loss | 7,132 | 6,339 |
Prior service cost (gain) | 5 | 6 |
Total AOCI | 7,137 | 6,345 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 572 | |
Prior service cost (credit) | 1 | |
Total net periodic benefit cost expected to be recognized during calendar year 2017 | 573 | |
Other Postretirement Benefit Plans, Defined Benefit | ||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract] | ||
Net (gain) loss | 1,595 | 1,704 |
Prior service cost (gain) | (694) | (1,087) |
Total AOCI | 901 | $ 617 |
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract] | ||
Net loss | 325 | |
Prior service cost (credit) | (368) | |
Total net periodic benefit cost expected to be recognized during calendar year 2017 | $ (43) |
Employee Benefit Plans_ Defined
Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract] | |||
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation | $ 2,569 | ||
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation | (2,191) | ||
Effect of One Percentage Point Increase on Service and Interest Cost Components | 156 | ||
Effect of One Percentage Point Decrease on Service and Interest Cost Components | $ (131) | ||
Healthcare trend rate pre-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Year Ultimate Trend Reached | 2,024 | 2,024 | |
Healthcare trend rate pre-65 | Black Hills Corporation - All Plans | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 6.10% | 6.35% | |
Healthcare trend rate pre-65 | Black Hills Service Company | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Ultimate trend rate | 4.50% | 4.50% | |
Healthcare trend rate post-65 | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Year Ultimate Trend Reached | 2,023 | 2,023 | |
Healthcare trend rate post-65 | Black Hills Corporation - All Plans | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 5.10% | 5.20% | |
Healthcare trend rate post-65 | Black Hills Service Company | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Ultimate trend rate | 4.50% | 4.50% | |
Supplemental Employee Retirement Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 4.02% | 4.28% | 4.19% |
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 | 4.28% | 4.19% | 5.03% |
Other Postretirement Benefit Plan | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 3.96% | 4.17% | 3.82% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Expected Long-term Return on Assets | 3.83% | 3.00% | 2.00% |
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 | 4.18% | 3.82% | 4.46% |
Pension Plans, Defined Benefit | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount Rate, Benefit Obligation | 4.27% | 4.58% | 4.19% |
Rate of Increase in Compensation Levels | 3.47% | 3.51% | 3.76% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Expected Long-term Return on Assets | 6.87% | 6.75% | 6.75% |
Rate of Compensation Increase | 3.42% | 3.76% | 3.76% |
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year | 6.75% | ||
Pension Plans, Defined Benefit | Black Hills Corporation Pension Plan | |||
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract] | |||
Trend for next year | 4.27% | ||
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 | 4.50% | 4.19% | 5.04% |
Expected Long-term Return on Assets | 6.75% | 6.75% |
Employee Benefit Plans_ Project
Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Pension Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | $ 21,355 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 21,566 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 23,010 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 27,028 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 27,614 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 149,893 |
Supplemental Employee Retirement Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 1,583 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 1,809 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 1,921 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 1,634 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 1,836 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 11,009 |
Other Postretirement Benefit Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 5,504 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 5,779 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 5,886 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 5,983 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 5,931 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 27,585 |
Commitments and Contingencie122
Commitments and Contingencies (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)MW | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Purchase Commitment | |||
Long-term Purchase Commitment [Line Items] | |||
Long Term Contract For Purchase of Fuel, Date of Contract Expiration | Dec. 31, 2044 | ||
Busch Ranch Wind Farm | Electric Utilities | |||
Long-term Purchase Commitment [Line Items] | |||
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage | 50.00% | ||
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 | MW | 50 | ||
Cost of Purchased Power | $ | $ 12,221 | $ 13,990 | $ 13,943 |
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 | MW | 50 | ||
Cost of Purchased Power | $ | $ 1,428 | 1,213 | 1,227 |
Happy Jack Wind Purchase Power Agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Sep. 3, 2028 | ||
Megawatts of Capacity Purchased | MW | 30 | ||
Happy Jack Wind Purchase Power Agreement | Renewable Wind Energy, Wyoming Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Power | $ | $ 3,836 | 3,155 | 3,919 |
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 | MW | 30 | ||
Silver Sage Wind Power Purchase Agreement | Renewable Wind Energy, Wyoming Electric | |||
Long-term Purchase Commitment [Line Items] | |||
Megawatts of Capacity Purchased | MW | 20 | ||
Cost of Purchased Power | $ | $ 4,949 | 4,107 | 4,798 |
Busch Ranch Wind Farm | |||
Long-term Purchase Commitment [Line Items] | |||
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Oct. 16, 2037 | ||
Megawatts of Capacity Purchased | MW | 14.5 | ||
Cost of Purchased Power | $ | $ 2,071 | 1,734 | 1,998 |
Cargill Power Purchase Agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Power | $ | $ 10,995 | $ 16,112 | $ 9,286 |
Commitments And Contingencies_
Commitments And Contingencies: Long-term Purchase Commitment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Natural Gas | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Natural Gas Purchases | $ 31,000 | $ 48,000 | $ 31,000 |
CIG Rockies | |||
Long-term Purchase Commitment [Line Items] | |||
2,017 | 5,549,427 | ||
2,018 | 0 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | 0 | ||
Enable East | |||
Long-term Purchase Commitment [Line Items] | |||
2,017 | 620,300 | ||
2,018 | 584,000 | ||
2,019 | 584,000 | ||
2,020 | 585,600 | ||
2,021 | 388,800 | ||
NWPL-Wyoming | |||
Long-term Purchase Commitment [Line Items] | |||
2,017 | 1,208,000 | ||
2,018 | 1,208,000 | ||
2,019 | 720,000 | ||
2,020 | 0 | ||
2,021 | 0 | ||
SSTAR-TEXOK | |||
Long-term Purchase Commitment [Line Items] | |||
2,017 | 457,399 | ||
2,018 | 0 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | 0 | ||
Other Natural Gas Indices | |||
Long-term Purchase Commitment [Line Items] | |||
2,017 | 44,913 | ||
2,018 | 0 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | $ 0 |
Commitments And Contingencie124
Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands | Dec. 31, 2016USD ($) |
Power Purchase Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2,017 | $ 26,690 |
2,018 | 8,934 |
2,019 | 6,388 |
2,020 | 6,388 |
2,021 | 5,755 |
Thereafter | 11,509 |
Transportation, Storage, Gathering And Coal Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2,017 | 136,607 |
2,018 | 120,123 |
2,019 | 87,210 |
2,020 | 82,247 |
2,021 | 75,424 |
Thereafter | $ 225,765 |
Commitments And Contingencie125
Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility - Purchase Option, Property $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)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 | $ | $ 2.6 |
Commitments And Contingencie126
Commitments And Contingencies: Power Sales Agreements (Details) | 12 Months Ended |
Dec. 31, 2016MW | |
M D U, Montana Dakota Utilities | |
Long-term Purchase Commitment [Line Items] | |
Megawatts Sold Under Long-Term Contract | 25 |
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 |
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, 2023 |
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 |
Commitments And Contingencie127
Commitments And Contingencies: Related Party Lease (Details) - Power purchased - Pueblo Airport Generation | 12 Months Ended |
Dec. 31, 2016MW | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Lease Expiration Date | Dec. 31, 2031 |
Number of Megawatts Capacity Purchased | 200 |
Commitments And Contingencie128
Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
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 Contingencie129
Commitments And Contingencies: Environmental Contingencies (Details) $ in Millions | Dec. 31, 2016USD ($) |
Electric Utilities | |
Loss Contingencies [Line Items] | |
Accrual for Environmental Loss Contingencies | $ 4.1 |
Gas Utilities | Manufactured Gas Plant | |
Loss Contingencies [Line Items] | |
Insurance Settlements Receivable, Noncurrent | 1.5 |
Loss Contingency, Range of Possible Loss | 1 |
Accrual for Environmental Loss Contingencies, Gross | 2.6 |
Gas Utilities | Manufactured Gas Plant | Minimum | |
Loss Contingencies [Line Items] | |
Loss Contingency, Range of Possible Loss | 2.6 |
Gas Utilities | Manufactured Gas Plant | Maximum | |
Loss Contingencies [Line Items] | |
Loss Contingency, Range of Possible Loss | $ 6.1 |
Guarantees (Details)
Guarantees (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 57,105 |
Mining | Surety Bond | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 57,105 |
Guarantor Obligations, Term | Ongoing |
Oil and Gas Reserves (Unaudi131
Oil and Gas Reserves (Unaudited): Oil and Gas Narrative (Details) Mcfe in Millions, $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)aGross-WellPUD_LocationMcfeState | |
Reserve Quantities [Line Items] | |
Wells in Process of Drilling | Gross-Well | 713 |
Gas and Oil Acreage, Leased | a | 127,919 |
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions | 0.1 |
Reserves Replaced | 0.00% |
Proved Undeveloped Reserves, Revisions of Previous Estimates | (9.4) |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0 |
Proved Developed Reserves (Energy) | 0 |
PUD Developed, PUD location | PUD_Location | 0 |
Capital Expenditure for Proved Undeveloped Reserve | $ | $ 0 |
Prior Year | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 6 |
Proved Undeveloped Reserves | 0.1 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0.4 |
Added Reserves | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0 |
Commodity Prices | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserves, Revisions of Previous Estimates | (12.3) |
Reserves Dropped | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 6 |
Proved Undeveloped Reserves | 0.1 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0.4 |
Oil and Gas Well Performance | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserves, Revisions of Previous Estimates | 3.5 |
Oil and Gas Reserve Revisions, Five Year Reserve Aging Limit | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Williston Basin | Prior Year | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 6 |
Proved Undeveloped Reserves | 0.1 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0.5 |
Williston Basin | Reserves Dropped | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 6 |
Proved Undeveloped Reserves | 0.1 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0.5 |
Piceance Basin | Prior Year | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ (0.1) |
Piceance Basin | Reserves Dropped | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0.1 |
Piceance Basin | Oil and Gas Reserve Revisions, Reserves Sold | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0 |
Powder River Basin | Prior Year | |
Reserve Quantities [Line Items] | |
Proved Undeveloped Reserve Locations | PUD_Location | 0 |
Proved Undeveloped Reserves | 0 |
Estimated Future Development Costs of Proved Undeveloped Wells | $ | $ 0 |
Oil and Gas | |
Reserve Quantities [Line Items] | |
Number of States in which Entity Operates | State | 9 |
Oil and Gas Reserves (Unaudi132
Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Oil and Gas - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |||
Proved Reserves | $ 0 | $ 1,407 | $ 4,881 |
Unproved Reserves | 910 | 669 | 5,056 |
Exploration Costs | 1,102 | 35,434 | 54,355 |
Development Costs | 4,657 | 128,998 | 52,262 |
Asset Retirement Obligation Incurred | 0 | 566 | 68 |
Oil and Gas Property Acquisition, Exploration, and Development Activities | $ 6,669 | $ 167,074 | $ 116,622 |
Oil and Gas Reserves (Unaudi133
Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details) | 12 Months Ended | ||
Dec. 31, 2016$ / bbl$ / MMcfMBblsMMcf | Dec. 31, 2015$ / bbl$ / MMcfMBblsMMcf | Dec. 31, 2014$ / bbl$ / MMcfMBblsMMcf | |
Proved Developed And Undevleoped Reserves [Roll Forward] | |||
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl | 42.75 | 50.28 | 94.99 |
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf | 2.48 | 2.59 | 4.35 |
Average Natural Gas Liquids Price Per MCF, NYMEX | $ / MMcf | 0 | 0 | 0 |
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl | 37.35 | 44.72 | 85.80 |
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf | 2.25 | 1.27 | 3.33 |
Average Natural Gas Liquids Price Per MCF, Wellhead | $ / MMcf | 11.92 | 18.96 | 34.81 |
Oil | |||
Proved Developed And Undevleoped Reserves [Roll Forward] | |||
Balance at Beginning of Year | MBbls | 3,450 | 4,276 | 3,921 |
Production | MBbls | (319) | (371) | (337) |
Additions, Acquisitions (Sales) | MBbls | (570) | (11) | (40) |
Additions, Extensions, Discoveries (bcfe) | MBbls | 3 | 199 | 733 |
Reserves, Revisions of Previous Estimates | MBbls | (322) | (643) | (1) |
Balance at End of Year | MBbls | 2,242 | 3,450 | 4,276 |
Proved Developed Reserves (Volume) | MBbls | 2,242 | 3,436 | 3,780 |
Proved Undeveloped Reserve (Volume) | MBbls | 0 | 14 | 496 |
Natural Gas | |||
Proved Developed And Undevleoped Reserves [Roll Forward] | |||
Balance at Beginning of Year | 73,412 | 65,440 | 63,190 |
Production | (9,430) | (10,058) | (7,156) |
Additions, Acquisitions (Sales) | (1,291) | (828) | (61) |
Additions, Extensions, Discoveries (bcfe) | 52 | 24,462 | 11,003 |
Reserves, Revisions of Previous Estimates | (8,173) | (5,604) | (1,536) |
Balance at End of Year | 54,570 | 73,412 | 65,440 |
Proved Developed Reserves (Volume) | 54,570 | 73,390 | 57,427 |
Proved Undeveloped Reserve (Volume) | 0 | 22 | 8,013 |
Natural Gas Liquids | |||
Proved Developed And Undevleoped Reserves [Roll Forward] | |||
Balance at Beginning of Year | 1,752 | 1,720 | 0 |
Production | (133) | (102) | (135) |
Additions, Acquisitions (Sales) | (17) | 0 | 0 |
Additions, Extensions, Discoveries (bcfe) | 0 | 232 | 182 |
Reserves, Revisions of Previous Estimates | 110 | (98) | 1,673 |
Balance at End of Year | 1,712 | 1,752 | 1,720 |
Proved Developed Reserves (Volume) | 1,712 | 1,752 | 1,530 |
Proved Undeveloped Reserve (Volume) | 0 | 0 | 191 |
Piceance Basin | |||
Reserve Quantities [Line Items] | |||
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 1.54 | ||
San Juan Basin | |||
Reserve Quantities [Line Items] | |||
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 0.92 | ||
Other Basin's | |||
Reserve Quantities [Line Items] | |||
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf | 0.53 |
Oil and Gas Reserves (Unaudi134
Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Unproved oil and gas properties | $ 18,547 | $ 47,254 | $ 75,329 |
Proved oil and gas properties | 1,043,558 | 1,008,466 | 807,518 |
Gross capitalized costs | 1,062,105 | 1,055,720 | 882,847 |
Accumulated depreciation, depletion and amortization and valuation allowances | (1,000,091) | (888,775) | (612,012) |
Net capitalized costs | $ 62,014 | $ 166,945 | $ 270,835 |
Oil and Gas Reserves (Unaudi135
Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Revenue | $ 34,058 | $ 43,283 | $ 55,114 |
Production costs | 17,231 | 19,762 | 22,155 |
Depreciation, depletion and amortization and valuation provisions | 12,574 | 28,062 | 23,288 |
Impairment of Oil and Gas Properties | 106,957 | 249,608 | 0 |
Total costs | 136,762 | 297,432 | 45,443 |
Results of operations from producing activities before tax | (102,704) | (254,149) | 9,671 |
Income tax benefit (expense) | 37,916 | 93,743 | (3,415) |
Results of operations from producing activities (excluding general and administrative costs and interest costs) | $ (64,788) | $ (160,406) | $ 6,256 |
Oil and Gas Reserves (Unaudi136
Oil and Gas Reserves (Unaudited): Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Leasehold acquisition cost | $ 10,241 | ||
Exploration cost | 7,416 | ||
Capitalized interest | 890 | ||
Total | 18,547 | ||
Current Year | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Leasehold acquisition cost | 963 | ||
Exploration cost | 532 | ||
Capitalized interest | 50 | ||
Total | 1,545 | ||
Prior Year | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Leasehold acquisition cost | 0 | ||
Exploration cost | 441 | ||
Capitalized interest | 23 | ||
Total | 464 | ||
More Than One Year, Less Than Two Years Prior | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Leasehold acquisition cost | 0 | ||
Exploration cost | 6,443 | ||
Capitalized interest | 335 | ||
Total | 6,778 | ||
More Than Two Years Prior | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Leasehold acquisition cost | 9,278 | ||
Exploration cost | 0 | ||
Capitalized interest | 482 | ||
Total | 9,760 | ||
Oil and Gas | |||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Interest Costs, Capitalized During Period | $ 900 | $ 1,000 | $ 1,000 |
Oil and Gas Reserves (Unaudi137
Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 246,221 | $ 295,173 | $ 675,973 | |
Future production costs | (166,248) | (146,552) | (245,180) | |
Future development costs, including plugging and abandonment | (18,333) | (24,833) | (45,123) | |
Future income tax expense | 0 | 0 | (29,523) | |
Future net cash flows | 61,640 | 123,788 | 356,147 | |
10% annual discount for estimated timing of cash flows | (26,574) | (44,760) | (173,125) | |
Standardized measure of discounted future net cash flows | $ 35,066 | $ 79,028 | $ 183,022 | $ 159,425 |
Oil and Gas Reserves (Unaudi138
Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure - beginning of year | $ 79,028 | $ 183,022 | $ 159,425 |
Sales and transfers of oil and gas produced, net of production costs | (4,314) | (29,948) | (32,139) |
Net changes in prices and production costs | (32,698) | (127,199) | (28,544) |
Extensions, discoveries and improved recovery, less related costs | 0 | 15,718 | 17,582 |
Changes in future development costs | 1,825 | (7,387) | 3,195 |
Development costs incurred during the period | 0 | 27,211 | 2,079 |
Revisions of previous quantity estimates | (7,477) | (6,941) | 23,722 |
Accretion of discount | 7,903 | 18,870 | 18,437 |
Net change in income taxes | 0 | 5,682 | 19,265 |
Purchases of reserves | 0 | 0 | 0 |
Sales of reserves | (9,201) | 0 | 0 |
Standardized measure - end of year | $ 35,066 | $ 79,028 | $ 183,022 |
Quarterly Historical Data (U139
Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Selected Quarterly Financial Information [Line Items] | |||||||||||
Revenue | $ 463,788 | $ 333,786 | $ 325,441 | $ 449,959 | $ 318,259 | $ 272,105 | $ 272,254 | $ 441,987 | $ 1,572,974 | $ 1,304,605 | $ 1,393,570 |
Operating income (loss) | 55,289 | 58,409 | 35,298 | 73,590 | 197 | (2,044) | (38,858) | 70,500 | 222,586 | 29,795 | 263,868 |
Income (loss) from continuing operations | 21,414 | 17,884 | 3,283 | 40,050 | (14,176) | (9,943) | (41,842) | 33,850 | |||
Net income (loss) available for common stock | $ 18,168 | $ 14,131 | $ 669 | $ 40,002 | $ (14,176) | $ (9,943) | $ (41,842) | $ 33,850 | $ 72,970 | $ (32,111) | $ 130,889 |
Earnings (loss) per share, Basic (usd per share) | $ 0.34 | $ 0.27 | $ 0.01 | $ 0.78 | $ (0.30) | $ (0.22) | $ (0.94) | $ 0.76 | $ 1.41 | $ (0.71) | $ 2.95 |
Earnings (loss) per share, Diluted (usd per share) | 0.33 | 0.26 | 0.01 | 0.77 | (0.30) | (0.22) | (0.94) | 0.76 | 1.37 | (0.71) | 2.93 |
Dividends per share paid (usd per share) | $ 0.420 | $ 0.420 | $ 0.420 | $ 0.420 | $ 0.405 | $ 0.405 | $ 0.405 | $ 0.405 | $ 1.68 | $ 1.62 | $ 1.56 |
Impairment Of Oil And Gas Properties, Net Of Tax | $ 34,000 | $ 7,900 | $ 16,000 | $ 8,800 | $ 44,000 | $ 36,000 | $ 66,000 | $ 14,000 | |||
Business Combination, Acquisition Related Costs, Net Of Tax | $ 5,500 | $ 4,100 | $ 4,100 | $ 15,000 | $ 3,700 | $ 2,800 | $ 500 | ||||
Common Stock | Maximum | |||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||
Share Price (usd per share) | $ 62.83 | $ 64.58 | $ 63.53 | $ 61.13 | $ 47.51 | $ 47.27 | $ 52.96 | $ 53.37 | |||
Common Stock | Minimum | |||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||
Share Price (usd per share) | $ 54.76 | $ 56.86 | $ 56.16 | $ 44.65 | $ 40 | $ 36.81 | $ 43.48 | $ 47.88 |
Schedule II Consolidated Val140
Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Allowance for Doubtful Accounts, Balance at Beginning of Year | $ 1,741 | $ 1,516 | $ 1,237 | |
Allowance for Doubtful Accounts, Adjustments | 2,158 | [1] | 0 | 0 |
Allowance for Doubtful Accounts, Charged to Cost and Expense | 2,704 | 3,860 | 4,470 | |
Allowance for Doubtful Accounts, Recoveries and Other Additions | 4,915 | 4,132 | 4,233 | |
Allowance for Doubtful Accounts, Write-Offs and Other Deductions | (9,126) | (7,767) | (8,424) | |
Allowance for Doubtful Accounts, Balance at End of Year | $ 2,392 | $ 1,741 | $ 1,516 | |
[1] | Represents allowance balances added with the SourceGas acquisition. |