Black Hills (BKH) 10-Q 10 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		51,587,415
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Loss) (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Revenue	$ 449,959	$ 441,987
Operating expenses:
Fuel, purchased power and cost of natural gas sold	171,856	205,327
Operations and maintenance	107,062	93,134
Depreciation, depletion and amortization	44,407	39,002
Taxes - property, production and severance	12,117	11,936
Impairment of Oil and Gas Properties	14,496	22,036
Other operating expenses	26,431	52
Total operating expenses	376,369	371,487
Operating income (loss)	73,590	70,500
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(32,074)	(19,910)
Allowance for funds used during construction - borrowed	501	158
Capitalized interest	235	276
Interest income	655	448
Allowance for funds used during construction - equity	707	56
Other income (expense), net	688	331
Total other income (expense), net	(29,288)	(18,641)
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	44,302	51,859
Equity in earnings (loss) of unconsolidated subsidiaries	0	(297)
Income tax benefit (expense)	(4,252)	(17,712)
Net income (loss)	40,050	33,850
Net income attributable to non-controlling interest	(48)	0
Net income (loss) available for common stock	$ 40,002	$ 33,850
Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic (usd per share)	$ 0.78	$ 0.76
Earnings (loss) per share, Diluted (usd per share)	$ 0.77	$ 0.76
Weighted average common shares outstanding:
Basic (in shares)	51,044	44,541
Diluted (in shares)	51,858	44,660
Dividends declared per share of common stock (usd per share)	$ 0.420	$ 0.405

Condensed Consolidated Stateme3

Condensed Consolidated Statement of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 40,050	$ 33,850
Other comprehensive income (loss), net of tax:
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $4,576 and $(1,042) for the three months ended 2016 and 2015, respectively)	(8,644)	1,836
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $1,946 and $1,254 for the three months ended 2016 and 2015, respectively)	(3,412)	(1,241)
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $15 for the three months ended 2016 and 2015, respectively)	0	(27)
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $19 for the three months ended 2016 and 2015, respectively)	(36)	(36)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(172) and $(247) for the three months ended 2016 and 2015, respectively)	322	458
Other comprehensive income (loss), net of tax	(11,770)	990
Comprehensive income (loss)	28,280	34,840
Less: comprehensive income attributable to non-controlling interest	(48)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 28,232	$ 34,840

Condensed Consolidated Stateme4

Condensed Consolidated Statement of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Fair value adjustment on derivatives designated as cash flow hedges, (tax) benefit	$ 4,576	$ 1,042
Reclassification adjustments of cash flow hedges settled and included in net income, (tax) benefit	1,946	1,254
Benefit plan liability adjustments net gain, (tax) benefit	0	15
Reclassification adjustment of benefit plan prior service cost included in net income, (tax) benefit	19	19
Reclassification adjustment of benefit plan liabilities actuarial gain (loss), (tax) benefit	$ (172)	$ (247)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Current assets:
Cash and cash equivalents	$ 46,974	$ 456,535	$ 63,385
Restricted cash and equivalents	1,839	1,697	2,191
Accounts receivable, net	206,276	147,486	178,421
Materials, supplies and fuel	78,176	86,943	66,626
Derivative assets, current	1,486	0	0
Income tax receivable, net	0	368	159
Deferred income tax assets, net, current	0	0	23,913
Regulatory assets, current	54,108	57,359	56,542
Other current assets	34,287	71,763	47,448
Total current assets	423,146	822,151	438,685
Investments	12,126	11,985	17,210
Property, plant and equipment	6,063,943	4,976,778	4,652,058
Less: accumulated depreciation and depletion	(1,742,070)	(1,717,684)	(1,407,214)
Total property, plant and equipment, net	4,321,873	3,259,094	3,244,844
Other assets:
Goodwill	1,306,169	359,759	353,396
Intangible assets, net	10,957	3,380	3,121
Regulatory assets, non-current	239,023	175,125	178,935
Derivative assets, non-current	85	3,441	0
Other assets, non-current	11,274	7,382	16,994
Total other assets, non-current	1,567,508	549,087	552,446
TOTAL ASSETS	6,324,653	4,642,317	4,253,185
Current liabilities:
Accounts payable	121,684	105,468	88,770
Accrued liabilities	272,181	232,061	166,781
Derivative liabilities, current	3,965	2,835	3,342
Accrued Income Taxes	10,899	0	0
Regulatory liabilities, current	35,933	4,865	17,621
Notes payable	215,600	76,800	102,600
Total current liabilities	660,262	422,029	379,114
Long-term debt, net of current maturities	3,159,055	1,853,682	1,531,372
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	500,202	450,579	503,117
Derivative liabilities, non-current	14,522	156	2,143
Regulatory liabilities, non-current	200,337	148,176	148,918
Benefit plan liabilities	181,270	146,459	162,334
Other deferred credits and other liabilities	124,181	155,369	154,604
Total deferred credits and other liabilities	$ 1,020,512	$ 900,739	$ 971,116
Commitments and contingencies (See Notes 9, 10, 17, 18)
Redeemable non-controlling interest	$ 4,141	$ 0	$ 0
Stockholders’ equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 51,477,472; 51,231,861; and 44,856,790 shares, respectively	51,477	51,232	44,857
Additional Paid in Capital	960,605	953,044	749,517
Retained earnings	490,999	472,534	592,951
Treasury stock, at cost – 30,903; 39,720; and 33,755 shares, respectively	(1,573)	(1,888)	(1,688)
Accumulated other comprehensive income (loss)	(20,825)	(9,055)	(14,054)
Total stockholders’ equity	1,480,683	1,465,867	1,371,583
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 6,324,653	$ 4,642,317	$ 4,253,185

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (unaudited) Condensed Consolidated Balance Sheets (Parentheticals) - $ / shares	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	51,477,472	51,231,861	44,856,790
Treasury Stock, Shares	30,903	39,720	33,755
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities:
Net income (loss) available for common stock	$ 40,002	$ 33,850
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	44,407	39,002
Deferred financing cost amortization	1,666	519
Impairment of long-lived assets	14,496	22,036
Stock compensation	4,461	2,083
Deferred income taxes	32,579	14,640
Employee benefit plans	3,466	5,283
Other adjustments, net	(5,000)	6,748
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	25,822	25,689
Accounts receivable, unbilled revenues and other operating assets	27,559	13,954
Accounts payable and other operating liabilities	(68,101)	(44,652)
Regulatory assets - current	12,856	20,272
Regulatory liabilities - current	11,613	13,721
Other operating activities, net	(7,489)	(1,658)
Net cash provided by (used in) operating activities	138,337	151,487
Investing activities:
Property, plant and equipment additions	(83,885)	(117,523)
Acquisition, net of long term debt assumed and cash acquired	(1,132,318)	0
Other investing activities	(329)	(348)
Net cash provided by (used in) investing activities	(1,216,532)	(117,871)
Financing activities:
Dividends paid on common stock	(21,537)	(18,148)
Common stock issued	7,821	999
Short-term borrowings - issuances	208,100	77,700
Short-term borrowings - repayments	(69,300)	(50,100)
Long-term debt - issuances	545,959	0
Other financing activities	(2,409)	(1,900)
Net cash provided by (used in) financing activities	668,634	8,551
Net change in cash and cash equivalents	(409,561)	42,167
Cash and Cash Equivalents
Cash and cash equivalents, beginning of period	456,535	21,218
Cash and cash equivalents, end of period	$ 46,974	$ 63,385

Management's Statement_

Management's Statement:	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Statement	MANAGEMENT’S STATEMENT The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2015 Annual Report on Form 10-K filed with the SEC. Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our utilities, other than the Oil and Gas segment, and in 2015 we began transitioning the Oil and Gas business to support utilities through a Cost of Service Gas Program. The following changes have been made to our Condensed Consolidated Statements of Income to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three months ended March 31, 2015: For the Three Months Ended March 31, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 71,084 $ (71,084 ) $ — Non-regulated energy operations and maintenance $ 22,050 $ (22,050 ) $ — Operations and maintenance $ — $ 93,134 $ 93,134 This presentation reclassification did not impact our financial position, results of operations or cash flows. Segment reporting transition of Cheyenne Light’s natural gas distribution Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior period has been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 3 for Revenues, Net Income and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the period ending March 31, 2015. This segment reclassification did not impact our consolidated financial position, results of operations or cash flows. Use of estimates and basis of presentation Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2016 , December 31, 2015 , and March 31, 2015 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2016 and March 31, 2015 , and our financial condition as of March 31, 2016 , December 31, 2015 , and March 31, 2015 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Significant Accounting Policies Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. Our significant assumptions and estimates can include, but are not limited to, the cash flows that an acquired entity is expected to generate in the future, the appropriate weighted-average cost of capital, and the savings expected to be derived from the business combination. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition. Recently Issued and Adopted Accounting Standards 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. The Company is currently assessing the impact that adoption of ASU 2016-09 will have on its consolidated financial position, results of operations, cash flows, and disclosure. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2019. 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. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have 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 will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . Debt issuance costs related to a recognized debt liability 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 March 31, 2016, we have presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million and $11 million in the Condensed Consolidated Balance Sheets as of December 31 2015 and March 31, 2015, respectively. Adoption of ASU 2015-03 did not have a material impact on our financial position. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments . This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of March 31, 2016. Adoption of this standard did not have a material impact on the Company’s financial position, results of operations or cash flows.

Acquisition_

Acquisition:	3 Months Ended
	Mar. 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 is subject to post-closing adjustments for capital expenditures, indebtedness and working capital, which will be determined and agreed to, subject to a review period. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock and 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, we recorded pre-tax acquisition costs of approximately $25 million in the three months ended March 31, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Condensed Consolidating Income Statements. No acquisition costs were recorded in the three months ended March 31, 2015. Our consolidated operating results for the three months ended March 31, 2016 include revenues of $76 million and net income of $7.6 million attributable to SourceGas for the period from February 12 through March 31, 2016. SourceGas is included in our Gas Utilities reporting segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. We are still determining the purchase price allocation for SourceGas. A preliminary purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.132 billion , net of long-term debt assumed of $760 million and cash acquired of $2.5 million , resulted in a preliminary estimate of goodwill totaling $946 million . These estimates are subject to change and will likely result in an increase or decrease in goodwill, which could be material. We have up to one year from the acquisition date to finalize the purchase price allocation. Approximately $219 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities. (in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Consideration Paid $ 1,134,882 Preliminary Allocation of Purchase Price: Current Assets $ 119,549 Property, plant & equipment, net 1,015,200 Goodwill 946,410 Deferred charges and other assets, excluding goodwill 136,240 Current liabilities (172,710 ) Long-term debt (760,000 ) Deferred credits and other liabilities (149,807 ) Total preliminary consideration paid $ 1,134,882 Conditions of Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below: The APSC order includes a 12 month base rate moratorium, an annual $0.25 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The CPUC order includes a two -year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three -year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The NPSC order includes a three -year base rate moratorium, a three -year continuation of the Choice Gas program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The WPSC order includes a three -year continuation of the Choice Gas program, as well as various other terms and reporting requirements. All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs are 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. Pro Forma Results We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the three months ended March 31, 2016 and March 31, 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results For the Three Months Ended March 31, 2016 March 31, 2015 (in thousands, except per share amounts) Revenue $ 528,921 $ 628,464 Net income (loss) available for common stock $ 66,690 $ 52,041 Earnings (loss) per share, Basic $ 1.31 $ 1.02 Earnings (loss) per share, Diluted $ 1.29 $ 1.01 We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the three months ended March 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 that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three months ended March 31, 2016 reflect lower gas pricing than in 2015 and tax benefits realized in the first quarter of 2016, as described in Footnote 20. 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 non-controlling 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 is provided a put option to sell us the retained interest.

Business Segment Information_

Business Segment Information:	3 Months Ended
	Mar. 31, 2016
Segment Reporting Information, Additional Information [Abstract]
Business Segment Information	BUSINESS SEGMENT INFORMATION Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended March 31, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric $ 163,531 $ 3,745 $ 19,215 Gas 268,667 1,806 31,975 Power Generation 1,852 21,456 8,582 Mining 7,534 8,748 2,938 Oil and Gas (a) 8,375 — (7,024 ) Corporate activities (b)(d) — — (15,684 ) Inter-company eliminations — (35,755 ) — Total $ 449,959 $ — $ 40,002 Three Months Ended March 31, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric (c) $ 166,493 $ 3,424 $ 17,553 Gas (c) 254,132 — 23,588 Power Generation 1,953 20,721 8,145 Mining 8,142 7,792 3,010 Oil and Gas (a) 11,267 — (19,115 ) Corporate activities — — 669 Inter-company eliminations — (31,937 ) — Total $ 441,987 $ — $ 33,850 (a) Net income (loss) for the three months ended March 31, 2016 and March 31, 2015 include non-cash after-tax ceiling test impairments of $8.8 million and $14 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million . See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue and Net Income of $16 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (d) Includes net income attributable to non-controlling interest of $0.1 million . Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: March 31, 2016 December 31, 2015 March 31, 2015 Segment: Electric (a) (b) $ 2,714,450 $ 2,720,004 $ 2,691,822 Gas (b) 3,146,315 999,778 960,435 Power Generation (a) 74,403 60,864 75,945 Mining 73,878 76,357 77,399 Oil and Gas (c) 197,291 208,956 348,300 Corporate activities (d) 118,316 576,358 99,284 Total assets $ 6,324,653 $ 4,642,317 $ 4,253,185 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $121 million , respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and March 31, 2015. (c) As a result of continued low commodity prices during 2016 and 2015, we recorded non-cash impairments of oil and gas assets included in our Oil and Gas segment of $14 million for the for the three months ended March 31, 2016 , $250 million for the year ended December 31, 2015, and $22 million for the three months ended March 31, 2015. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016.

Accounts Receivable_

Accounts Receivable:	3 Months Ended
	Mar. 31, 2016
Receivables [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts March 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,981 $ 32,660 $ (772 ) $ 73,869 Gas Utilities 73,259 55,014 (4,363 ) 123,910 Power Generation 1,210 — — 1,210 Mining 2,484 — — 2,484 Oil and Gas 2,395 — (13 ) 2,382 Corporate 2,421 — — 2,421 Total $ 123,750 $ 87,674 $ (5,148 ) $ 206,276 Accounts Unbilled Less Allowance for Accounts December 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,331 32,869 (1,001 ) 62,199 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,025 — — 1,025 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 Accounts Unbilled Less Allowance for Accounts March 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 49,046 $ 23,088 $ (873 ) $ 71,261 Gas Utilities (a) 68,068 30,237 (1,549 ) 96,756 Power Generation 1,152 — — 1,152 Mining 3,638 — — 3,638 Oil and Gas 4,646 — (13 ) 4,633 Corporate 981 — — 981 Total $ 127,531 $ 53,325 $ (2,435 ) $ 178,421 ___________ (a) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $6.3 million as of December 31, 2015 and March 31, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

Regulatory Accounting_

Regulatory Accounting:	3 Months Ended
	Mar. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Accounting	REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) March 31, 2016 December 31, 2015 March 31, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 24,479 $ 24,751 $ 30,833 Deferred gas cost adjustments (a)(d) 1 14,895 15,521 6,138 Gas price derivatives (a) 7 20,324 23,583 21,606 AFUDC (b) 45 13,677 12,870 12,114 Employee benefit plans (c) (e) 12 111,661 83,986 97,700 Environmental (a) subject to approval 1,162 1,180 1,240 Asset retirement obligations (a) 44 487 457 3,237 Bond issue cost (a) 22 3,097 3,133 3,240 Renewable energy standard adjustment (b) 5 4,507 5,068 5,590 Flow through accounting (c) 35 30,614 29,722 26,835 Decommissioning costs (f) 10 18,134 18,310 13,702 Gas supply contract termination 5 30,613 — — Other regulatory assets (a) 15 19,481 13,903 13,242 $ 293,131 $ 232,484 $ 235,477 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 40,797 $ 7,814 $ 18,094 Employee benefit plans (c) (e) 12 63,580 47,218 53,151 Cost of removal (a) 44 123,076 90,045 81,449 Other regulatory liabilities (c) 25 8,817 7,964 13,845 $ 236,270 $ 153,041 $ 166,539 __________ (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 December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $13 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements vary, currently ranging from $6 to $8 per MMBtu, and exceed market prices. We recorded a liability for this contract in our purchase price allocation. We applied for and subsequent to March 31, 2016, we were granted approval to terminate these agreements with the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We settled the liability on April 29, 2016. See Note 22.

Materials, Supplies and Fuel_

Materials, Supplies and Fuel:	3 Months Ended
	Mar. 31, 2016
Inventory, Net [Abstract]
Materials, Supplies and Fuel	MATERIALS, SUPPLIES AND FUEL The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Materials and supplies $ 66,542 $ 55,726 $ 52,429 Fuel - Electric Utilities 5,365 5,567 6,780 Natural gas in storage held for distribution 6,269 25,650 7,417 Total materials, supplies and fuel $ 78,176 $ 86,943 $ 66,626

Goodwill & Intangible Assets_

Goodwill & Intangible Assets:	3 Months Ended
	Mar. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	GOODWILL & INTANGIBLE ASSETS Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 250,487 $ 100,507 $ 8,765 $ 359,759 Acquisition of SourceGas (a) — 946,410 — 946,410 Ending balance at March 31, 2016 $ 250,487 $ 1,046,917 $ 8,765 $ 1,306,169 __________ (a) Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. (b) Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details. Following is a summary of Intangible assets included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Intangible assets, net beginning balance December 31, 2015 $ 3,380 Additions, net (a) 7,734 Amortization expense (157 ) Intangible assets, net, ending balance at March 31, 2016 $ 10,957 __________ (a) Intangible assets, net acquired from SourceGas are primarily trademarks and tradenames, and are amortized over 5 -year estimated useful lives. See Note 2 for more information.

Earnings Per Share_

Earnings Per Share:	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended March 31, 2016 2015 Net income (loss) available for common stock $ 40,002 $ 33,850 Weighted average shares - basic 51,044 44,541 Dilutive effect of: Equity Units (a) 720 — Equity compensation 94 119 Weighted average shares - diluted 51,858 44,660 __________ (a) Calculated using the treasury stock method. The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended March 31, 2016 2015 Equity compensation 74 107 Anti-dilutive shares 74 107

Notes Payable_

Notes Payable:	3 Months Ended
	Mar. 31, 2016
Notes Payable [Abstract]
Short-term Debt [Text Block]	NOTES PAYABLE We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 215,600 $ 24,000 $ 76,800 $ 33,399 $ 102,600 $ 22,300 Revolving Credit Facility On June 26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through June 26, 2020 . This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million . 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 S&P and/or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125% , 1.125% , and 1.125% , respectively, at March 31, 2016 . A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating. Debt Financial Covenants On February 12, 2016, in connection with the SourceGas Acquisition discussed in Note 2 , our Revolving Credit Facility and Term Loan credit agreements were amended to permit the assumption of certain indebtedness of SourceGas and to increase the Recourse Leverage Ratio, and we amended and restated SourceGas’s $340 million term loan due June 30, 2017. On February 12, 2016, the maximum Recourse Leverage Ratio increased to 0.75 to 1.00 for the next four fiscal quarters; it was previously 0.65 to 1.00 . Additionally, covenants within Black Hills Gas Holdings financing agreements require Black Hills Gas Holdings to maintain a consolidated debt to capitalization ratio of no more than 0.75 to 1.00 . Except as provided above, our Revolving Credit Facility, our Term Loan and the SourceGas term loan require compliance with the following financial covenant at the end of each quarter: As of March 31, 2016 Covenant Requirement Recourse Leverage Ratio 71% Less than 75% As of March 31, 2016 , we were in compliance with this covenant.

Long-Term Debt_

Long-Term Debt:	3 Months Ended
	Mar. 31, 2016
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT Long-term debt was as follows (dollars in thousands): Interest Rate at March 31, 2016 March 31, 2016 December 31, 2015 March 31, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (892 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,822 ) (1,890 ) (2,095 ) Senior unsecured notes due July 15, 2020 5.88% 200,000 200,000 200,000 Senior unsecured notes due January 11, 2019 2.50% 250,000 — — Unamortized discount on Senior unsecured notes due 2019 (282 ) — — Corporate term loan due June 30, 2017 (a) (b) 1.38% 340,000 — — Corporate term loan due April 12, 2017 (b) 1.40% 300,000 300,000 — Corporate term loan due June 19, 2015 (b) 1.31% — — 275,000 Total Corporate Debt 2,211,004 1,322,110 997,905 Gas Utilities Senior secured notes due September 29, 2019 (a) (e) 3.98% 95,000 — — Senior unsecured notes due April 1, 2017 (a) 5.90% 325,000 — — Unamortized discount on Senior unsecured notes due 2017 (103 ) — — 419,897 — — Electric Utilities First Mortgage Bonds due October 20, 2044 4.43% 85,000 85,000 85,000 First Mortgage Bonds due October 20, 2044 4.53% 75,000 75,000 75,000 First Mortgage Bonds due August 15, 2032 7.23% 75,000 75,000 75,000 First Mortgage Bonds due November 1, 2039 6.13% 180,000 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (97 ) (99 ) (102 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (c) 0.45% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (c) 0.47% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (c) 0.85% 2,855 2,855 2,855 Total Electric Utilities Debt 544,758 544,756 544,753 Total long-term debt 3,175,659 1,866,866 1,542,658 Less current maturities — — — Less deferred financing costs (d) (16,604 ) (13,184 ) (11,286 ) Long-term debt, net of current maturities $ 3,159,055 $ 1,853,682 $ 1,531,372 _______________ (a) Long-term debt assumed with the SourceGas Acquisition. (b) Variable interest rate, based on LIBOR plus a spread. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $1.6 million , $1.7 million and $1.6 million as of March 31, 2016, December 31, 2015 and March 31, 2015, respectively. (e) Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2016 $ — 2017 $ 965,000 2018 $ — 2019 $ 345,000 2020 $ 200,000 Thereafter $ 1,668,855 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at March 31, 2016. Debt Transactions On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consisted of $300 million of 3.95% , 10 -year senior notes due 2026, and $250 million of 2.50% , 3 -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 will be amortized over the life of each respective note. Assumption of Long-Term Debt At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following: • $325 million , 5.9% senior unsecured notes with an original issue date of April 16, 2007 due April 1, 2017. • $95 million , 3.98% senior secured notes with an original issue date of September 29, 2014 due September 29, 2019. • $340 million unsecured corporate term loan due June 30, 2017. Interest expense under this term loan is LIBOR plus a margin of 0.875% .

Equity_

Equity:	3 Months Ended
	Mar. 31, 2016
Statement of Stockholders' Equity [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	( 11 ) EQUITY A summary of the changes in equity is as follows: Three Months Ended March 31, 2016 Total Stockholders’ Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 Net income (loss) available for common stock 40,002 Other comprehensive income (loss) (11,770 ) Dividends on common stock (21,543 ) Share-based compensation 561 Issuance of common stock 6,824 Dividend reinvestment and stock purchase plan 755 Other stock transactions (13 ) Balance at March 31, 2016 $ 1,480,683 Three Months Ended March 31, 2015 Total Stockholders’ Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 Net income (loss) available for common stock 33,850 Other comprehensive income 990 Dividends on common stock (18,148 ) Share-based compensation 209 Issuance of common stock — Dividend reinvestment and stock purchase plan 798 Other stock transactions — Balance at March 31, 2015 $ 1,371,583 At-the-Market Equity Offering Program On March 18, 2016, we implemented an at-the-market 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. We have issued 121,000 common shares for $7.0 million , net of $0.1 million in fees and issuance costs with settlement dates through March 31, 2016 under the ATM equity offering program. Additionally, 140,000 shares for net proceeds of $8.4 million have been offered, but were not yet settled as of March 31, 2016.

Risk Management Activities_

Risk Management Activities:	3 Months Ended
	Mar. 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 operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2015 Annual Report on Form 10-K. Market Risk Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to: • Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production; and our fuel procurement for certain of our gas-fired generation assets; and • Interest rate risk associated with our variable-rate debt and anticipated future refinancings. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and in Note 13 . Oil and Gas We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows. To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly. The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Notional (a) 159,000 3,447,500 198,000 4,392,500 305,000 5,367,500 Maximum terms in months (b) 1 1 1 1 1 1 Derivative assets, current $ — $ — $ — $ — $ — $ — Derivative assets, non-current $ — $ — $ — $ — $ — $ — Derivative liabilities, current $ — $ — $ — $ — $ — $ — Derivative liabilities, non-current $ — $ — $ — $ — $ — $ — __________ (a) Crude oil in Bbls, natural gas in MMBtus. (b) Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument. Based on March 31, 2016 prices, a $7.6 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate. Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used for Electric Utility generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, fixed to float swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss), or the Condensed Consolidated Statements of Comprehensive Income (Loss). For hedging activities associated with our retail marketing operations, the effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of: March 31, 2016 December 31, 2015 March 31, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 18,270,000 57 20,580,000 60 17,280,000 69 Natural gas options purchased 990,000 21 2,620,000 3 1,320,000 12 Natural gas basis swaps purchased 16,810,000 57 18,150,000 60 15,735,000 57 Natural gas fixed for float swaps purchased (b) 2,374,000 23 — 0 — 0 Natural gas fixed for float swaps sold (b) 816,989 15 — 0 — 0 Natural gas physical purchases 2,948,250 12 — 0 — 0 Natural gas physical sales 813,200 11 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) 1,109,500 MMBtus and 112,500 MMBtus were designated as cash flow hedges for the natural gas swaps purchased and sold, respectively. We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands): March 31, 2016 December 31, 2015 March 31, 2015 Derivative assets, current $ 1,486 $ — $ — Derivative assets, non-current $ 85 $ — $ — Derivative liabilities, current $ 1,675 $ — $ — Derivative liabilities, non-current $ 44 $ — $ — Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities $ 20,324 $ 23,578 $ 21,606 Financing Activities We entered into pay fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Interest Rate Swaps (a) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (b) Notional $ 150,000 $ 250,000 $ 75,000 $ 250,000 $ 75,000 $ 75,000 Weighted average fixed interest rate 2.09 % 2.29 % 4.97 % 2.29 % 4.97 % 4.97 % Maximum terms in years 1.08 1.08 0.75 1.33 1.00 1.75 Derivative assets, non-current $ — $ — $ — $ 3,441 $ — $ — Derivative liabilities, current $ — $ — $ 2,290 $ — $ 2,835 $ 3,342 Derivative liabilities, non-current $ 3,785 $ 10,693 $ — $ — $ 156 $ 2,143 __________ (a) These swaps are designated as cash flow hedges of anticipated debt refinancings. (b) These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings. Based on March 31, 2016 market interest rates and balances related to our interest rate swaps, a loss of approximately $2.3 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change. Cash Flow Hedges The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended March 31, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (15,047 ) Interest expense $ 1,709 $ — Commodity derivatives 1,589 Revenue 3,592 — Commodity derivatives 238 Fuel, purchased power and cost of natural gas sold 57 Fuel, purchased power and cost of natural gas sold — Total $ (13,220 ) $ 5,358 $ — Three Months Ended March 31, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (886 ) Interest expense $ 1,437 $ — Commodity derivatives 3,764 Revenue (3,932 ) — Total $ 2,878 $ (2,495 ) $ —

Fair Value Measurements_

Fair Value Measurements:	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Derivative Financial Instruments The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information see Notes 1, 8, 9 and 10 to the Consolidated Financial Statements included in our 2015 Annual Report on Form 10-K filed with the SEC. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Oil and Gas Segment: • The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures 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. Utilities Segments: • The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter swaps, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty on a daily basis. The fair value of these swaps include a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Corporate Activities: • The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that takes into account our credit ratings, and the credit rating of our counterparty. Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of March 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 4,668 — (4,668 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 3,761 — (3,761 ) — Commodity derivatives — Utilities — 3,070 — (1,499 ) 1,571 Interest Rate Swaps — — — — — Total $ — $ 11,499 $ — $ (9,928 ) $ 1,571 Liabilities: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 250 — (250 ) — Commodity derivatives — Utilities — 23,428 — (21,709 ) 1,719 Interest rate swaps — 16,768 — — 16,768 Total $ — $ 40,446 $ — $ (21,959 ) $ 18,487 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 6,309 — (6,309 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,335 — (4,335 ) — 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 Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 556 — (556 ) — Commodity derivatives — Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of March 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 8,096 — (8,096 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 6,526 — (6,526 ) — Commodity derivatives — Utilities — 1,184 — (1,184 ) — Interest Rate Swaps — — — — — Total $ — $ 15,806 $ — $ (15,806 ) $ — Liabilities: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 2 — (2 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 256 — (256 ) — Commodity derivatives — Utilities — 22,002 — (22,002 ) — Interest rate swaps — 5,485 — — 5,485 Total $ — $ 27,745 $ — $ (22,260 ) $ 5,485 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. However, the amounts do not include net cash collateral on deposit in margin accounts at March 31, 2016 , December 31, 2015 , and March 31, 2015 , to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 12 . The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of March 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 7,986 $ — Commodity derivatives Derivative assets — non-current 607 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 982 Commodity derivatives Derivative liabilities — non-current — 71 Interest rate swaps Derivative liabilities — current — 2,290 Interest rate swaps Derivative liabilities — non-current — 14,478 Total derivatives designated as hedges $ 8,593 $ 17,821 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,326 $ — Commodity derivatives Derivative assets — non-current 79 — Commodity derivatives Derivative liabilities — current — 9,117 Commodity derivatives Derivative liabilities — non-current — 12,009 Total derivatives not designated as hedges $ 1,405 $ 21,126 As of December 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,981 $ — Commodity derivatives Derivative assets — non-current 663 — Interest rate swaps Derivative assets — non-current 3,441 — Commodity derivatives Derivative liabilities — current — 465 Commodity derivatives Derivative liabilities — non-current — 91 Interest rate swaps Derivative liabilities — current — 2,835 Interest rate swaps Derivative liabilities — non-current — 156 Total derivatives designated as hedges $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 9,586 Commodity derivatives Derivative liabilities — non-current — 12,706 Total derivatives not designated as hedges $ — $ 22,292 As of March 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,989 $ — Commodity derivatives Derivative assets — non-current 4,633 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 126 Commodity derivatives Derivative liabilities — non-current — 132 Interest rate swaps Derivative liabilities — current — 3,342 Interest rate swaps Derivative liabilities — non-current — 2,143 Total derivatives designated as hedges $ 14,622 $ 5,743 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 7,530 Commodity derivatives Derivative liabilities — non-current — 13,288 Total derivatives not designated as hedges $ — $ 20,818

Fair Value of Financial Instrum

Fair Value of Financial Instruments:	3 Months Ended
	Mar. 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 13 , were as follows (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 46,974 $ 46,974 $ 456,535 $ 456,535 $ 63,385 $ 63,385 Restricted cash and equivalents (a) $ 1,839 $ 1,839 $ 1,697 $ 1,697 $ 2,191 $ 2,191 Notes payable (a) $ 215,600 $ 215,600 $ 76,800 $ 76,800 $ 102,600 $ 102,600 Long-term debt, including current maturities (b) $ 3,159,055 $ 3,392,652 $ 1,853,682 $ 1,992,274 $ 1,531,372 $ 1,767,113 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Other Comprehensive Income (Los

Other Comprehensive Income (Loss):	3 Months Ended
	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss)	OTHER COMPREHENSIVE INCOME (LOSS) The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended March 31, 2016 March 31, 2015 Gains (losses) on cash flow hedges: Interest rate swaps Interest expense $ (1,709 ) $ 1,437 Commodity contracts Revenue (3,592 ) (3,932 ) Commodity contracts Fuel, purchased power and cost of natural gas sold (57 ) — (5,358 ) (2,495 ) Income tax Income tax benefit (expense) 1,946 1,254 Reclassification adjustments related to cash flow hedges, net of tax $ (3,412 ) $ (1,241 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) Actuarial gain (loss) Operations and maintenance 494 705 439 650 Income tax Income tax benefit (expense) (153 ) (228 ) Reclassification adjustments related to defined benefit plans, net of tax $ 286 $ 422 Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands): Derivatives Designated as Cash Flow Hedges Employee Benefit Plans Total Balance as of December 31, 2014 $ 5,093 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss), net of tax 595 395 990 Balance as of March 31, 2015 $ 5,688 $ (19,742 ) $ (14,054 ) Balance as of December 31, 2015 $ 6,725 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss), net of tax (12,056 ) 286 (11,770 ) Balance as of March 31, 2016 $ (5,331 ) $ (15,494 ) $ (20,825 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information:	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Three months ended March 31, 2016 March 31, 2015 (in thousands) Non-cash investing and financing activities from continuing operations— Property, plant and equipment acquired with accrued liabilities $ 30,260 $ 33,534 Cash (paid) refunded during the period for continuing operations— Interest (net of amounts capitalized) $ (15,528 ) $ (10,909 ) Income taxes, net $ — $ (2 )

Employee Benefit Plans_

Employee Benefit Plans:	3 Months Ended
	Mar. 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 non-pension defined benefit postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement. In accordance with ASC 715, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a regulated asset account and will be amortized over the average remaining service life of the plans. Amounts recognized in the Condensed Consolidated Balance Sheet upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Unfunded postretirement benefit obligation $ 22,187 $ 11,751 Defined Benefit Pension Plans We have three defined benefit pension plans for certain eligible employees consisting of the Black Hills Corporation pension plan, Black Hills Utility Holdings’ pension plan and the SourceGas retirement plan. The benefits for the pension plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. All Pension Plans have been closed to new employees and frozen for certain employees who did not meet age and service based criteria. Beginning in 2016, we changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 interest costs are 3.827% , 3.817% and 3.284% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.575% for pension, 4.500% for supplemental non-qualified defined benefit and 4.165% for other postretirement benefit costs. The decrease in the 2016 service and interest costs is approximately $2.8 million , $0.3 million and $0.4 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method. In connection with the acquisition related re-measurement of the SourceGas benefit plans we adopted the spot yield curve method, referenced above. The discount rates used to measure the 2016 interest costs are 3.690% for pension and 3.319% for other post retirement costs. The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 2,078 $ 1,494 Interest cost 3,936 3,880 Expected return on plan assets (5,765 ) (4,867 ) Prior service cost 15 15 Net loss (gain) 1,793 2,759 Net periodic benefit cost $ 2,057 $ 3,281 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. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market health care exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market health care exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 467 $ 464 Interest cost 485 450 Expected return on plan assets (70 ) (33 ) Prior service cost (benefit) (107 ) (107 ) Net loss (gain) 84 102 Net periodic benefit cost $ 859 $ 876 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 29 $ 491 Interest cost 314 364 Prior service cost — 1 Net loss (gain) 207 270 Net periodic benefit cost $ 550 $ 1,126 Contributions We anticipate that we will make contributions to the benefit plans in 2016 and 2017 . Contributions to the Defined Benefit Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands): Contributions Made Additional Contributions Contributions Three Months Ended March 31, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ — $ 10,200 $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 3,576 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 1,176 $ 1,627

Commitments and Contingencies_

Commitments and Contingencies:	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES There have been no significant changes to commitments and contingencies from those previously disclosed in Note 18 of our Notes to the Consolidated Financial Statements in our 2015 Annual Report on Form 10-K except for those described below and in Notes 2 and 21. Gas Supply Agreements Acquired Utilities In connection with the SourceGas Acquisition (see Note 2), we assumed various commitments relating to natural gas supply and transportation commitments and lease commitments, as summarized below (in thousands): 2016 2017 2018 2019 2020 Thereafter Total Future minimum payments Pipeline capacity obligations $ 37,062 $ 45,248 $ 44,434 $ 40,636 $ 40,636 $ 192,651 $ 400,667 Facilities and equipment 1,755 2,216 2,207 1,676 1,359 3,326 12,539 Total $ 38,817 $ 47,464 $ 46,641 $ 42,312 $ 41,995 $ 195,977 $ 413,206 Build Transfer Agreement On November 2, 2015, Colorado Electric executed a build-transfer agreement with Invenergy Wind Development Colorado, LLC to purchase the 60 MW, $109 million Peak View Wind Project. Peak View will be built by Invenergy Wind Development Colorado, LLC approximately 30 miles south of Pueblo, Colorado, in Huerfano and Las Animas counties. The estimated cost of $109 million includes taxes, transmission infrastructure and interconnection costs. Construction started in February of 2016 and is expected to be completed in late 2016. Under the build transfer agreement, Colorado Electric makes progress payments, which started in late 2015, and continue through completion of the project. Ownership of Peak View will transfer to Colorado Electric prior to commercial operation and will be operated as a utility-owned asset. BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric. At March 31, 2016, BHC’s guarantee was approximately $85 million . The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the second anniversary of the closing date. The balance of the guarantee decreases as progress payments are made. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2016 , we were in compliance with the debt covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at March 31, 2016 : • Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2016 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million .

Impairment of Assets_

Impairment of Assets:	3 Months Ended
	Mar. 31, 2016
Asset Impairment Charges [Abstract]
Asset Impairment Charges [Text Block]	IMPAIRMENT OF ASSETS Long-lived Assets Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. In determining the ceiling value of our assets under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. As a result of continued low commodity prices in 2016 and throughout 2015, we have recorded the following non-cash impairments of our oil and gas assets included in our Oil and Gas segment for the three months ended March 31, 2016 and March 31, 2015. • During the first quarter of 2016, we recorded a $14 million pre-tax non-cash impairment of oil and gas assets included in our Oil and Gas segment. For natural gas, the average NYMEX price was $2.40 per Mcf, adjusted to $1.13 per Mcf at the wellhead; for crude oil, the average NYMEX price was $46.26 per barrel, adjusted to $39.80 per barrel at the wellhead. • During the first quarter of 2015, we recorded a $22 million pre-tax non-cash impairment of oil and gas assets included in our Oil and Gas segment. For natural gas, the average NYMEX price was $3.88 per Mcf, adjusted to $2.69 per Mcf at the wellhead; for crude oil, the average NYMEX price was $82.72 per barrel, adjusted to $74.13 per barrel at the wellhead.

Income Taxes_

Income Taxes:	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended March 31, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 2.6 1.2 Percentage depletion in excess of cost (a) (14.1 ) (1.0 ) Accounting for uncertain tax positions adjustment (b) (11.4 ) 1.9 Inter-period tax allocation (4.0 ) (1.5 ) Transaction costs 2.5 — Other tax differences (1.0 ) (1.2 ) 9.6 % 34.4 % __________ (a) The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties and represents a change in estimate for income tax accounting purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (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 after-tax interest expense and tax credits that were previously accrued 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. In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We expect the reversal of approximately $26 million of the liability for unrecognized tax benefits to occur in 2016. The vast majority of such reversal will be to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $11 million excluding interest.

Accrued Liabilities_

Accrued Liabilities:	3 Months Ended
	Mar. 31, 2016
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities Disclosure [Text Block]	ACCRUED LIABILITIES The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Accrued employee compensation, benefits and withholdings $ 90,295 $ 43,342 $ 32,090 Accrued property taxes 40,638 32,393 32,835 Accrued payments related to litigation expenses and settlements — 38,750 25,000 Gas-gathering contract (a) 39,944 — — Customer deposits and prepayments 26,042 53,496 16,210 Accrued interest and contract adjustment payments 43,119 25,762 21,559 CIAC current portion 20,466 14,745 — Other (none of which is individually significant) 11,677 23,573 39,087 Total accrued liabilities $ 272,181 $ 232,061 $ 166,781 __________ (a) This contract was settled on April 29, 2016. See Note 22 for additional information.

Subsequent Event_

Subsequent Event:	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTS Settlement of Gas Supply Contract On April 29, 2016, we settled for $40 million a Black Hills Gas Holdings gas supply 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. The majority of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under this contract vary, currently ranging from $6 to $8 per MMBtu and exceed 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 the net buyout costs associated with the contract termination to create a regulatory asset and recover the majority of costs over a five year period. At March 31, 2016, this payment was in Accrued liabilities on the Condensed Consolidated Balance Sheets. Sale of Non-controlling 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% , non-controlling interest in Black Hills Colorado IPP for $215 million to AIA Energy North America LLC, an infrastructure investment platform managed by Argo Infrastructure Partners. FERC approval of the sale was received on March 29, 2016. Black Hills Colorado IPP continues to own 50.1% and 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.

Management's Statement_ Busines

Management's Statement: Business Description (Policies)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Segment Reporting, Policy	Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our utilities, other than the Oil and Gas segment, and in 2015 we began transitioning the Oil and Gas business to support utilities through a Cost of Service Gas Program.
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. Our significant assumptions and estimates can include, but are not limited to, the cash flows that an acquired entity is expected to generate in the future, the appropriate weighted-average cost of capital, and the savings expected to be derived from the business combination. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for our acquisition.

Management's Statement_ Busin31

Management's Statement: Business Description (Tables)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Segment Reporting	The following changes have been made to our Condensed Consolidated Statements of Income to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three months ended March 31, 2015: For the Three Months Ended March 31, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 71,084 $ (71,084 ) $ — Non-regulated energy operations and maintenance $ 22,050 $ (22,050 ) $ — Operations and maintenance $ — $ 93,134 $ 93,134 Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended March 31, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric $ 163,531 $ 3,745 $ 19,215 Gas 268,667 1,806 31,975 Power Generation 1,852 21,456 8,582 Mining 7,534 8,748 2,938 Oil and Gas (a) 8,375 — (7,024 ) Corporate activities (b)(d) — — (15,684 ) Inter-company eliminations — (35,755 ) — Total $ 449,959 $ — $ 40,002 Three Months Ended March 31, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric (c) $ 166,493 $ 3,424 $ 17,553 Gas (c) 254,132 — 23,588 Power Generation 1,953 20,721 8,145 Mining 8,142 7,792 3,010 Oil and Gas (a) 11,267 — (19,115 ) Corporate activities — — 669 Inter-company eliminations — (31,937 ) — Total $ 441,987 $ — $ 33,850 (a) Net income (loss) for the three months ended March 31, 2016 and March 31, 2015 include non-cash after-tax ceiling test impairments of $8.8 million and $14 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million . See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue and Net Income of $16 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (d) Includes net income attributable to non-controlling interest of $0.1 million .

Acquisition_ Acquisition (Table

Acquisition: Acquisition (Tables)	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Business Combination, Separately Recognized Transactions	(in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Consideration Paid $ 1,134,882 Preliminary Allocation of Purchase Price: Current Assets $ 119,549 Property, plant & equipment, net 1,015,200 Goodwill 946,410 Deferred charges and other assets, excluding goodwill 136,240 Current liabilities (172,710 ) Long-term debt (760,000 ) Deferred credits and other liabilities (149,807 ) Total preliminary consideration paid $ 1,134,882
Business Combination, Pro Forma Information	The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results For the Three Months Ended March 31, 2016 March 31, 2015 (in thousands, except per share amounts) Revenue $ 528,921 $ 628,464 Net income (loss) available for common stock $ 66,690 $ 52,041 Earnings (loss) per share, Basic $ 1.31 $ 1.02 Earnings (loss) per share, Diluted $ 1.29 $ 1.01

Business Segment Information_ B

Business Segment Information: Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting Information, Additional Information [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following changes have been made to our Condensed Consolidated Statements of Income to reflect combined operations and maintenance expenses, rather than by business group as previously reported, for the three months ended March 31, 2015: For the Three Months Ended March 31, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 71,084 $ (71,084 ) $ — Non-regulated energy operations and maintenance $ 22,050 $ (22,050 ) $ — Operations and maintenance $ — $ 93,134 $ 93,134 Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended March 31, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric $ 163,531 $ 3,745 $ 19,215 Gas 268,667 1,806 31,975 Power Generation 1,852 21,456 8,582 Mining 7,534 8,748 2,938 Oil and Gas (a) 8,375 — (7,024 ) Corporate activities (b)(d) — — (15,684 ) Inter-company eliminations — (35,755 ) — Total $ 449,959 $ — $ 40,002 Three Months Ended March 31, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Segment: Electric (c) $ 166,493 $ 3,424 $ 17,553 Gas (c) 254,132 — 23,588 Power Generation 1,953 20,721 8,145 Mining 8,142 7,792 3,010 Oil and Gas (a) 11,267 — (19,115 ) Corporate activities — — 669 Inter-company eliminations — (31,937 ) — Total $ 441,987 $ — $ 33,850 (a) Net income (loss) for the three months ended March 31, 2016 and March 31, 2015 include non-cash after-tax ceiling test impairments of $8.8 million and $14 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million . See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue and Net Income of $16 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (d) Includes net income attributable to non-controlling interest of $0.1 million .
Reconciliation of Assets from Segment to Consolidated	Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: March 31, 2016 December 31, 2015 March 31, 2015 Segment: Electric (a) (b) $ 2,714,450 $ 2,720,004 $ 2,691,822 Gas (b) 3,146,315 999,778 960,435 Power Generation (a) 74,403 60,864 75,945 Mining 73,878 76,357 77,399 Oil and Gas (c) 197,291 208,956 348,300 Corporate activities (d) 118,316 576,358 99,284 Total assets $ 6,324,653 $ 4,642,317 $ 4,253,185 __________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $121 million , respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and March 31, 2015. (c) As a result of continued low commodity prices during 2016 and 2015, we recorded non-cash impairments of oil and gas assets included in our Oil and Gas segment of $14 million for the for the three months ended March 31, 2016 , $250 million for the year ended December 31, 2015, and $22 million for the three months ended March 31, 2015. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016.

Accounts Receivable_ Accounts R

Accounts Receivable: Accounts Receivable (Tables)	3 Months Ended
	Mar. 31, 2016
Receivables [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts March 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,981 $ 32,660 $ (772 ) $ 73,869 Gas Utilities 73,259 55,014 (4,363 ) 123,910 Power Generation 1,210 — — 1,210 Mining 2,484 — — 2,484 Oil and Gas 2,395 — (13 ) 2,382 Corporate 2,421 — — 2,421 Total $ 123,750 $ 87,674 $ (5,148 ) $ 206,276 Accounts Unbilled Less Allowance for Accounts December 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 41,679 $ 35,874 $ (727 ) $ 76,826 Gas Utilities (a) 30,331 32,869 (1,001 ) 62,199 Power Generation 1,187 — — 1,187 Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,025 — — 1,025 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 Accounts Unbilled Less Allowance for Accounts March 31, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 49,046 $ 23,088 $ (873 ) $ 71,261 Gas Utilities (a) 68,068 30,237 (1,549 ) 96,756 Power Generation 1,152 — — 1,152 Mining 3,638 — — 3,638 Oil and Gas 4,646 — (13 ) 4,633 Corporate 981 — — 981 Total $ 127,531 $ 53,325 $ (2,435 ) $ 178,421

Regulatory Accounting_ Regulato

Regulatory Accounting: Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) March 31, 2016 December 31, 2015 March 31, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 24,479 $ 24,751 $ 30,833 Deferred gas cost adjustments (a)(d) 1 14,895 15,521 6,138 Gas price derivatives (a) 7 20,324 23,583 21,606 AFUDC (b) 45 13,677 12,870 12,114 Employee benefit plans (c) (e) 12 111,661 83,986 97,700 Environmental (a) subject to approval 1,162 1,180 1,240 Asset retirement obligations (a) 44 487 457 3,237 Bond issue cost (a) 22 3,097 3,133 3,240 Renewable energy standard adjustment (b) 5 4,507 5,068 5,590 Flow through accounting (c) 35 30,614 29,722 26,835 Decommissioning costs (f) 10 18,134 18,310 13,702 Gas supply contract termination 5 30,613 — — Other regulatory assets (a) 15 19,481 13,903 13,242 $ 293,131 $ 232,484 $ 235,477 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 40,797 $ 7,814 $ 18,094 Employee benefit plans (c) (e) 12 63,580 47,218 53,151 Cost of removal (a) 44 123,076 90,045 81,449 Other regulatory liabilities (c) 25 8,817 7,964 13,845 $ 236,270 $ 153,041 $ 166,539 __________ (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 December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $13 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements vary, currently ranging from $6 to $8 per MMBtu, and exceed market prices. We recorded a liability for this contract in our purchase price allocation. We applied for and subsequent to March 31, 2016, we were granted approval to terminate these agreements with the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We settled the liability on April 29, 2016. See Note 22.

Materials, Supplies and Fuel_ M

Materials, Supplies and Fuel: Materials, Supplies and Fuel (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory, Net [Abstract]
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Materials and supplies $ 66,542 $ 55,726 $ 52,429 Fuel - Electric Utilities 5,365 5,567 6,780 Natural gas in storage held for distribution 6,269 25,650 7,417 Total materials, supplies and fuel $ 78,176 $ 86,943 $ 66,626

Goodwill & Intangible Assets_ G

Goodwill & Intangible Assets: Goodwill & Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 250,487 $ 100,507 $ 8,765 $ 359,759 Acquisition of SourceGas (a) — 946,410 — 946,410 Ending balance at March 31, 2016 $ 250,487 $ 1,046,917 $ 8,765 $ 1,306,169 __________ (a) Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. (b) Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details.
Schedule of Indefinite-Lived Intangible Assets	Intangible assets, net beginning balance December 31, 2015 $ 3,380 Additions, net (a) 7,734 Amortization expense (157 ) Intangible assets, net, ending balance at March 31, 2016 $ 10,957 __________ (a) Intangible assets, net acquired from SourceGas are primarily trademarks and tradenames, and are amortized over 5 -year estimated useful lives. See Note 2 for more information.

Earnings Per Share_ Earnings Pe

Earnings Per Share: Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended March 31, 2016 2015 Net income (loss) available for common stock $ 40,002 $ 33,850 Weighted average shares - basic 51,044 44,541 Dilutive effect of: Equity Units (a) 720 — Equity compensation 94 119 Weighted average shares - diluted 51,858 44,660 __________ (a) Calculated using the treasury stock method.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended March 31, 2016 2015 Equity compensation 74 107 Anti-dilutive shares 74 107

Notes Payable_ Notes Payable an

Notes Payable: Notes Payable and Long-term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Short-term Debt	We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 215,600 $ 24,000 $ 76,800 $ 33,399 $ 102,600 $ 22,300
Schedule of Credit Facility Covenants	our Revolving Credit Facility, our Term Loan and the SourceGas term loan require compliance with the following financial covenant at the end of each quarter: As of March 31, 2016 Covenant Requirement Recourse Leverage Ratio 71% Less than 75%

Long-Term Debt_ Long-Term Debt

Long-Term Debt: Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt was as follows (dollars in thousands): Interest Rate at March 31, 2016 March 31, 2016 December 31, 2015 March 31, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (892 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,822 ) (1,890 ) (2,095 ) Senior unsecured notes due July 15, 2020 5.88% 200,000 200,000 200,000 Senior unsecured notes due January 11, 2019 2.50% 250,000 — — Unamortized discount on Senior unsecured notes due 2019 (282 ) — — Corporate term loan due June 30, 2017 (a) (b) 1.38% 340,000 — — Corporate term loan due April 12, 2017 (b) 1.40% 300,000 300,000 — Corporate term loan due June 19, 2015 (b) 1.31% — — 275,000 Total Corporate Debt 2,211,004 1,322,110 997,905 Gas Utilities Senior secured notes due September 29, 2019 (a) (e) 3.98% 95,000 — — Senior unsecured notes due April 1, 2017 (a) 5.90% 325,000 — — Unamortized discount on Senior unsecured notes due 2017 (103 ) — — 419,897 — — Electric Utilities First Mortgage Bonds due October 20, 2044 4.43% 85,000 85,000 85,000 First Mortgage Bonds due October 20, 2044 4.53% 75,000 75,000 75,000 First Mortgage Bonds due August 15, 2032 7.23% 75,000 75,000 75,000 First Mortgage Bonds due November 1, 2039 6.13% 180,000 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (97 ) (99 ) (102 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (c) 0.45% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (c) 0.47% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (c) 0.85% 2,855 2,855 2,855 Total Electric Utilities Debt 544,758 544,756 544,753 Total long-term debt 3,175,659 1,866,866 1,542,658 Less current maturities — — — Less deferred financing costs (d) (16,604 ) (13,184 ) (11,286 ) Long-term debt, net of current maturities $ 3,159,055 $ 1,853,682 $ 1,531,372 _______________ (a) Long-term debt assumed with the SourceGas Acquisition. (b) Variable interest rate, based on LIBOR plus a spread. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $1.6 million , $1.7 million and $1.6 million as of March 31, 2016, December 31, 2015 and March 31, 2015, respectively. (e) Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness.
Schedule of Maturities of Long-term Debt [Table Text Block]	Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2016 $ — 2017 $ 965,000 2018 $ — 2019 $ 345,000 2020 $ 200,000 Thereafter $ 1,668,855

Equity_ Equity (Tables)

Equity: Equity (Tables)	3 Months Ended
	Mar. 31, 2016
Statement of Stockholders' Equity [Abstract]
Schedule of Stockholders Equity [Table Text Block]	A summary of the changes in equity is as follows: Three Months Ended March 31, 2016 Total Stockholders’ Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 Net income (loss) available for common stock 40,002 Other comprehensive income (loss) (11,770 ) Dividends on common stock (21,543 ) Share-based compensation 561 Issuance of common stock 6,824 Dividend reinvestment and stock purchase plan 755 Other stock transactions (13 ) Balance at March 31, 2016 $ 1,480,683 Three Months Ended March 31, 2015 Total Stockholders’ Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 Net income (loss) available for common stock 33,850 Other comprehensive income 990 Dividends on common stock (18,148 ) Share-based compensation 209 Issuance of common stock — Dividend reinvestment and stock purchase plan 798 Other stock transactions — Balance at March 31, 2015 $ 1,371,583

Risk Management Activities_ Ris

Risk Management Activities: Risk Management Activities (Tables)	3 Months Ended
	Mar. 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 Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Interest Rate Swaps (a) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (b) Notional $ 150,000 $ 250,000 $ 75,000 $ 250,000 $ 75,000 $ 75,000 Weighted average fixed interest rate 2.09 % 2.29 % 4.97 % 2.29 % 4.97 % 4.97 % Maximum terms in years 1.08 1.08 0.75 1.33 1.00 1.75 Derivative assets, non-current $ — $ — $ — $ 3,441 $ — $ — Derivative liabilities, current $ — $ — $ 2,290 $ — $ 2,835 $ 3,342 Derivative liabilities, non-current $ 3,785 $ 10,693 $ — $ — $ 156 $ 2,143 __________ (a) These swaps are designated as cash flow hedges of anticipated debt refinancings. (b) These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings.
Contract or Notional Amounts and Terms of Commodity Derivatives	The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of: March 31, 2016 December 31, 2015 March 31, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 18,270,000 57 20,580,000 60 17,280,000 69 Natural gas options purchased 990,000 21 2,620,000 3 1,320,000 12 Natural gas basis swaps purchased 16,810,000 57 18,150,000 60 15,735,000 57 Natural gas fixed for float swaps purchased (b) 2,374,000 23 — 0 — 0 Natural gas fixed for float swaps sold (b) 816,989 15 — 0 — 0 Natural gas physical purchases 2,948,250 12 — 0 — 0 Natural gas physical sales 813,200 11 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) 1,109,500 MMBtus and 112,500 MMBtus were designated as cash flow hedges for the natural gas swaps purchased and sold, respectively.
Derivative Instruments, Gain (Loss)	The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended March 31, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (15,047 ) Interest expense $ 1,709 $ — Commodity derivatives 1,589 Revenue 3,592 — Commodity derivatives 238 Fuel, purchased power and cost of natural gas sold 57 Fuel, purchased power and cost of natural gas sold — Total $ (13,220 ) $ 5,358 $ — Three Months Ended March 31, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (886 ) Interest expense $ 1,437 $ — Commodity derivatives 3,764 Revenue (3,932 ) — Total $ 2,878 $ (2,495 ) $ —
Oil and Gas [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Crude Oil Futures, Swaps and Options Natural Gas Futures and Swaps Notional (a) 159,000 3,447,500 198,000 4,392,500 305,000 5,367,500 Maximum terms in months (b) 1 1 1 1 1 1 Derivative assets, current $ — $ — $ — $ — $ — $ — Derivative assets, non-current $ — $ — $ — $ — $ — $ — Derivative liabilities, current $ — $ — $ — $ — $ — $ — Derivative liabilities, non-current $ — $ — $ — $ — $ — $ — __________ (a) Crude oil in Bbls, natural gas in MMBtus. (b) Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
Utilities Group [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands): March 31, 2016 December 31, 2015 March 31, 2015 Derivative assets, current $ 1,486 $ — $ — Derivative assets, non-current $ 85 $ — $ — Derivative liabilities, current $ 1,675 $ — $ — Derivative liabilities, non-current $ 44 $ — $ — Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities $ 20,324 $ 23,578 $ 21,606

Fair Value Measurements_ Fair V

Fair Value Measurements: Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy, Measured on Recurring Basis	The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of March 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 4,668 — (4,668 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 3,761 — (3,761 ) — Commodity derivatives — Utilities — 3,070 — (1,499 ) 1,571 Interest Rate Swaps — — — — — Total $ — $ 11,499 $ — $ (9,928 ) $ 1,571 Liabilities: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 250 — (250 ) — Commodity derivatives — Utilities — 23,428 — (21,709 ) 1,719 Interest rate swaps — 16,768 — — 16,768 Total $ — $ 40,446 $ — $ (21,959 ) $ 18,487 As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 6,309 — (6,309 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,335 — (4,335 ) — 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 Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 556 — (556 ) — Commodity derivatives — Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of March 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 8,096 — (8,096 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 6,526 — (6,526 ) — Commodity derivatives — Utilities — 1,184 — (1,184 ) — Interest Rate Swaps — — — — — Total $ — $ 15,806 $ — $ (15,806 ) $ — Liabilities: Commodity derivatives — Oil and Gas Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 2 — (2 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 256 — (256 ) — Commodity derivatives — Utilities — 22,002 — (22,002 ) — Interest rate swaps — 5,485 — — 5,485 Total $ — $ 27,745 $ — $ (22,260 ) $ 5,485
Schedule of Derivative Instruments Balance Sheet Location	The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of March 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 7,986 $ — Commodity derivatives Derivative assets — non-current 607 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 982 Commodity derivatives Derivative liabilities — non-current — 71 Interest rate swaps Derivative liabilities — current — 2,290 Interest rate swaps Derivative liabilities — non-current — 14,478 Total derivatives designated as hedges $ 8,593 $ 17,821 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,326 $ — Commodity derivatives Derivative assets — non-current 79 — Commodity derivatives Derivative liabilities — current — 9,117 Commodity derivatives Derivative liabilities — non-current — 12,009 Total derivatives not designated as hedges $ 1,405 $ 21,126 As of December 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,981 $ — Commodity derivatives Derivative assets — non-current 663 — Interest rate swaps Derivative assets — non-current 3,441 — Commodity derivatives Derivative liabilities — current — 465 Commodity derivatives Derivative liabilities — non-current — 91 Interest rate swaps Derivative liabilities — current — 2,835 Interest rate swaps Derivative liabilities — non-current — 156 Total derivatives designated as hedges $ 14,085 $ 3,547 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 9,586 Commodity derivatives Derivative liabilities — non-current — 12,706 Total derivatives not designated as hedges $ — $ 22,292 As of March 31, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 9,989 $ — Commodity derivatives Derivative assets — non-current 4,633 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 126 Commodity derivatives Derivative liabilities — non-current — 132 Interest rate swaps Derivative liabilities — current — 3,342 Interest rate swaps Derivative liabilities — non-current — 2,143 Total derivatives designated as hedges $ 14,622 $ 5,743 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 7,530 Commodity derivatives Derivative liabilities — non-current — 13,288 Total derivatives not designated as hedges $ — $ 20,818

Fair Value of Financial Instr44

Fair Value of Financial Instruments: Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 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 13 , were as follows (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 46,974 $ 46,974 $ 456,535 $ 456,535 $ 63,385 $ 63,385 Restricted cash and equivalents (a) $ 1,839 $ 1,839 $ 1,697 $ 1,697 $ 2,191 $ 2,191 Notes payable (a) $ 215,600 $ 215,600 $ 76,800 $ 76,800 $ 102,600 $ 102,600 Long-term debt, including current maturities (b) $ 3,159,055 $ 3,392,652 $ 1,853,682 $ 1,992,274 $ 1,531,372 $ 1,767,113 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Other Comprehensive Income (L45

Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Tables)	3 Months Ended
	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Reclassification Out of Accumulated Other Comprehensive Income (Loss)	The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended March 31, 2016 March 31, 2015 Gains (losses) on cash flow hedges: Interest rate swaps Interest expense $ (1,709 ) $ 1,437 Commodity contracts Revenue (3,592 ) (3,932 ) Commodity contracts Fuel, purchased power and cost of natural gas sold (57 ) — (5,358 ) (2,495 ) Income tax Income tax benefit (expense) 1,946 1,254 Reclassification adjustments related to cash flow hedges, net of tax $ (3,412 ) $ (1,241 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) Actuarial gain (loss) Operations and maintenance 494 705 439 650 Income tax Income tax benefit (expense) (153 ) (228 ) Reclassification adjustments related to defined benefit plans, net of tax $ 286 $ 422
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands): Derivatives Designated as Cash Flow Hedges Employee Benefit Plans Total Balance as of December 31, 2014 $ 5,093 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss), net of tax 595 395 990 Balance as of March 31, 2015 $ 5,688 $ (19,742 ) $ (14,054 ) Balance as of December 31, 2015 $ 6,725 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss), net of tax (12,056 ) 286 (11,770 ) Balance as of March 31, 2016 $ (5,331 ) $ (15,494 ) $ (20,825 )

Supplemental Disclosure of Ca46

Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Tables)	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Three months ended March 31, 2016 March 31, 2015 (in thousands) Non-cash investing and financing activities from continuing operations— Property, plant and equipment acquired with accrued liabilities $ 30,260 $ 33,534 Cash (paid) refunded during the period for continuing operations— Interest (net of amounts capitalized) $ (15,528 ) $ (10,909 ) Income taxes, net $ — $ (2 )

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures	Amounts recognized in the Condensed Consolidated Balance Sheet upon the February 12, 2016 acquisition are (in thousands): Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Plans Unfunded postretirement benefit obligation $ 22,187 $ 11,751
Schedule of Net Benefit Costs	The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 2,078 $ 1,494 Interest cost 3,936 3,880 Expected return on plan assets (5,765 ) (4,867 ) Prior service cost 15 15 Net loss (gain) 1,793 2,759 Net periodic benefit cost $ 2,057 $ 3,281 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. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market health care exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market health care exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 467 $ 464 Interest cost 485 450 Expected return on plan assets (70 ) (33 ) Prior service cost (benefit) (107 ) (107 ) Net loss (gain) 84 102 Net periodic benefit cost $ 859 $ 876 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended March 31, 2016 2015 Service cost $ 29 $ 491 Interest cost 314 364 Prior service cost — 1 Net loss (gain) 207 270 Net periodic benefit cost $ 550 $ 1,126
Schedule of Defined Benefit Plans Contributions	Contributions and anticipated contributions are as follows (in thousands): Contributions Made Additional Contributions Contributions Three Months Ended March 31, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ — $ 10,200 $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 3,576 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 1,176 $ 1,627

Commitments and Contingencies_

Commitments and Contingencies: Supply Commitment (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment [Table Text Block]	we assumed various commitments relating to natural gas supply and transportation commitments and lease commitments, as summarized below (in thousands): 2016 2017 2018 2019 2020 Thereafter Total Future minimum payments Pipeline capacity obligations $ 37,062 $ 45,248 $ 44,434 $ 40,636 $ 40,636 $ 192,651 $ 400,667 Facilities and equipment 1,755 2,216 2,207 1,676 1,359 3,326 12,539 Total $ 38,817 $ 47,464 $ 46,641 $ 42,312 $ 41,995 $ 195,977 $ 413,206

Income Taxes_ Income Taxes (Tab

Income Taxes: Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended March 31, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 2.6 1.2 Percentage depletion in excess of cost (a) (14.1 ) (1.0 ) Accounting for uncertain tax positions adjustment (b) (11.4 ) 1.9 Inter-period tax allocation (4.0 ) (1.5 ) Transaction costs 2.5 — Other tax differences (1.0 ) (1.2 ) 9.6 % 34.4 % __________ (a) The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties and represents a change in estimate for income tax accounting purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (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 after-tax interest expense and tax credits that were previously accrued 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. In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We expect the reversal of approximately $26 million of the liability for unrecognized tax benefits to occur in 2016. The vast majority of such reversal will be to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $11 million excluding interest.

Accrued Liabilities_ Accrued Li

Accrued Liabilities: Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities [Table Text Block]	The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2016 December 31, 2015 March 31, 2015 Accrued employee compensation, benefits and withholdings $ 90,295 $ 43,342 $ 32,090 Accrued property taxes 40,638 32,393 32,835 Accrued payments related to litigation expenses and settlements — 38,750 25,000 Gas-gathering contract (a) 39,944 — — Customer deposits and prepayments 26,042 53,496 16,210 Accrued interest and contract adjustment payments 43,119 25,762 21,559 CIAC current portion 20,466 14,745 — Other (none of which is individually significant) 11,677 23,573 39,087 Total accrued liabilities $ 272,181 $ 232,061 $ 166,781 __________ (a) This contract was settled on April 29, 2016. See Note 22 for additional information.

Management's Statement_ Segment

Management's Statement: Segment Reporting (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Costs, Nonregulated Energy Operations		$ 0
Utilities - Operating and maintenance		0
Operations and maintenance	$ 107,062	93,134
Utilities Group [Member]
Prior Period Reclassification Adjustment		(71,084)
Utilities Group [Member] | Scenario, Previously Reported [Member]
Prior Period Reclassification Adjustment		71,084
Non Regulated Energy Group [Member]
Prior Period Reclassification Adjustment		(22,050)
Non Regulated Energy Group [Member] | Scenario, Previously Reported [Member]
Prior Period Reclassification Adjustment		$ 22,050

Management's Statement_ Simplif

Management's Statement: Simplifying The Presentation Of Debt Issuance Costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Mar. 31, 2015
Deferred Finance Costs [Member]
Prior Period Reclassification Adjustment	$ 13	$ 11

Acquisition_ Acquisition (Detai

Acquisition: Acquisition (Details) $ / shares in Units, $ in Thousands	Feb. 12, 2016USD ($)customerutilitymi	Jan. 13, 2016USD ($)	Nov. 23, 2015USD ($)shares	Mar. 31, 2016USD ($)$ / shares		Mar. 31, 2015USD ($)$ / shares	Dec. 31, 2015USD ($)
Acquisition Narrative [Abstract]
Proceeds From Issuance Of Common Stock and Sale Of Interest In Corporate Units			$ 536,000
Long-term debt - issuances		$ 546,000		$ 545,959		$ 0
Revenue				449,959		441,987
Net income (loss) available for common stock				40,002		33,850
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired				1,132,318		0
Acquisition Recap [Abstract]
Goodwill				$ 1,306,169		353,396	$ 359,759
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma - Combined Federal and State income Tax Rate				37.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners				0.50%
Corporate[Member]
Acquisition Narrative [Abstract]
Business Acquisition, Transaction Costs				$ 25,000
Revenue				0		0
Net income (loss) available for common stock				(15,684)	[1],[2]	669
Remarketable Junior Subordinated Notes Due 2028 [Member]
Acquisition Narrative [Abstract]
Debt Instrument, Convertible, Number of Equity Instruments | shares			5,980,000
Common Stock [Member]
Acquisition Narrative [Abstract]
Stock Issued During Period, Shares, New Issues | shares			6,325,000
Source Gas [Member]
Acquisition Narrative [Abstract]
Number Of Natural Gas Utilities Acquired | utility	4
Number Of Customers Acquired | customer	429,000
Length Of Natural Gas Pipeline Acquired | mi	512
Revenue				76,000
Net income (loss) available for common stock				7,600
Cash Acquired from Acquisition	$ 2,500
Goodwill, Expected Tax Deductible Amount				219,000
Acquisition Recap [Abstract]
Preliminary Purchase Price	1,894,882
Consideration paid	1,134,882
Current Assets	119,549
Property, plant & equipment, net	1,015,200
Goodwill	946,410
Deferred charges and other assets, excluding goodwill	136,240
Current liabilities	(172,710)
Long-term debt	(760,000)
Deferred credits and other liabilities	$ (149,807)
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma - Revenue				528,921		628,464
Pro Forma - Net income (loss) available for common stock				$ 66,690		$ 52,041
Pro Forma - Earnings per share, Basic (usd per share) | $ / shares				$ 1.31		$ 1.02
Pro Forma - Earnings per share, Diluted (usd per share) | $ / shares				$ 1.29		$ 1.01
Source Gas [Member] | Black Hills Energy, Arkansas [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Base Rate Moratorium Imposed by ASPC	12 months
Annual Amount of Customer Credit				$ 250
Source Gas [Member] | Black Hills Gas Distribution, Colorado [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Annual Amount of Customer Credit				$ 200
Duration of Base Rate Moratorium imposed by CPUC	3 years
Source Gas [Member] | Black Hills Gas Distribution - Nebraska [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by NPSC	3 years
Continuation Period of Choice Gas Program	3 years
Source Gas [Member] | Rocky Mountain Natural Gas [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by CPUC	2 years
Source Gas [Member] | Black Hills Gas Distribution - Wyoming [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Continuation Period of Choice Gas Program	3 years
Source Gas [Member] | Maximum [Member] | Black Hills Energy, Arkansas [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit	5 years
Source Gas [Member] | Maximum [Member] | Black Hills Gas Distribution, Colorado [Member]
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit	5 years
[1]	Includes net income attributable to non-controlling interest of $0.1 million.
[2]	Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Business Segment Information_ I

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands		3 Months Ended				12 Months Ended
		Mar. 31, 2016		Mar. 31, 2015		Dec. 31, 2015
Segment Reporting Information
Impairment of Oil and Gas Properties		$ 14,496		$ 22,036
Revenue		449,959		441,987
Net income (loss) available for common stock		40,002		33,850
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest		48		0
Inter-company eliminations [Member]
Segment Reporting Information
Revenue		(35,755)		(31,937)
Net income (loss) available for common stock		0		0
Corporate activities[Member]
Segment Reporting Information
Revenue		0		0
Net income (loss) available for common stock		(15,684)	[1],[2]	669
Business Acquisition, Transaction Costs		25,000
Consolidation, Eliminations [Member]
Segment Reporting Information
Revenue		0		0
Electric Utilities [Member]
Segment Reporting Information
Revenue		163,531		166,493	[3]
Net income (loss) available for common stock		19,215		17,553	[3]
Electric Utilities [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		3,745		3,424	[3]
Gas Utilities [Member]
Segment Reporting Information
Revenue		268,667		254,132	[3]
Net income (loss) available for common stock		31,975		23,588	[3]
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest		(100)
Gas Utilities [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		1,806		0	[3]
Power Generation [Member]
Segment Reporting Information
Revenue		1,852		1,953
Net income (loss) available for common stock		8,582		8,145
Power Generation [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		21,456		20,721
Mining [Member]
Segment Reporting Information
Revenue		7,534		8,142
Net income (loss) available for common stock		2,938		3,010
Mining [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		8,748		7,792
Oil and Gas [Member]
Segment Reporting Information
Impairment of Oil and Gas Properties		14,000		22,000		$ 250,000
Revenue		8,375		11,267
Net income (loss) available for common stock	[4]	(7,024)		(19,115)
Impairment of Oil and Gas Properties Net of Tax		8,800		14,000
Oil and Gas [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		0		0
Incremental, Non-Recurring Acquisition Costs (Net of Tax) [Member] | Corporate activities[Member]
Segment Reporting Information
Business Acquisition, Transaction Costs		15,000
Labor (Net Of Tax) [Member] | Corporate activities[Member]
Segment Reporting Information
Business Acquisition, Transaction Costs		$ 3,800
Revenue [Member]
Segment Reporting Information
Prior Period Reclassification Adjustment				16,000
Net Income (Loss) Available to Common Stockholders, Basic [Member]
Segment Reporting Information
Prior Period Reclassification Adjustment				$ 1,400
[1]	Includes net income attributable to non-controlling interest of $0.1 million.
[2]	Net income (loss) for the three months ended March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $15 million and after-tax internal labor costs attributable to the acquisition of $3.8 million. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
[3]	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue and Net Income of $16 million and $1.4 million, respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment.
[4]	Net income (loss) for the three months ended March 31, 2016 and March 31, 2015 include non-cash after-tax ceiling test impairments of $8.8 million and $14 million, respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Business Segment Information_ S

Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands		3 Months Ended				12 Months Ended
		Mar. 31, 2016		Mar. 31, 2015		Dec. 31, 2015
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		$ 6,324,653		$ 4,253,185		$ 4,642,317
Impairment of Oil and Gas Properties		14,496		22,036
Corporate activities[Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		118,316		99,284		576,358	[1]
Electric Utilities [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	[2]	2,714,450		2,691,822	[3]	2,720,004	[3]
Gas Utilities [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		3,146,315		960,435	[3]	999,778	[3]
Power Generation [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	[2]	74,403		75,945		60,864
Mining [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		73,878		77,399		76,357
Oil and Gas [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		197,291	[4]	348,300		208,956
Impairment of Oil and Gas Properties		$ 14,000		22,000		250,000
Assets, Total [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Prior Period Reclassification Adjustment Balance Sheet				$ 121,000		135,000
Cash and Cash Equivalents [Member] | Corporate activities[Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets						$ 440,000
[1]	Corporate assets at December 31, 2015 included approximately $440 million of cash from the November 23, 2015 equity offerings, which was used to partially fund the SourceGas acquisition on February 12, 2016.
[2]	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
[3]	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility assets as of the three months ended March 31, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $121 million, respectively, previously reported in the Electric Utility segment in 2015 are now presented in the Gas Utility segment as of December 31, 2015 and March 31, 2015.
[4]	As a result of continued low commodity prices during 2016 and 2015, we recorded non-cash impairments of oil and gas assets included in our Oil and Gas segment of $14 million for the for the three months ended March 31, 2016, $250 million for the year ended December 31, 2015, and $22 million for the three months ended March 31, 2015. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable_ Accounts56

Accounts Receivable: Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015		Mar. 31, 2015
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (5,148)	$ (1,741)		$ (2,435)
Accounts receivable, net	206,276	147,486		178,421
Corporate[Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	2,421	1,025		981
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(772)	(727)	[1]	(873)	[1]
Accounts receivable, net	73,869	76,826	[1]	71,261	[1]
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(4,363)	(1,001)	[1]	(1,549)	[1]
Accounts receivable, net	123,910	62,199	[1]	96,756	[1]
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	1,210	1,187		1,152
Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	2,484	2,760		3,638
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(13)		(13)
Accounts receivable, net	2,382	3,489		4,633
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	123,750	80,484		127,531
Billed Revenues [Member] | Corporate[Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,421	1,025		981
Billed Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	41,981	41,679	[1]	49,046	[1]
Billed Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	73,259	30,331	[1]	68,068	[1]
Billed Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,210	1,187		1,152
Billed Revenues [Member] | Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,484	2,760		3,638
Billed Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,395	3,502		4,646
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	87,674	68,743		53,325
Unbilled Revenues [Member] | Corporate[Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0		0
Unbilled Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	32,660	35,874	[1]	23,088	[1]
Unbilled Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	55,014	32,869	[1]	30,237	[1]
Unbilled Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0		0
Unbilled Revenues [Member] | Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0		0
Unbilled Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 0	0		0
Accounts Receivable, Trade
Accounts Receivable [Line Items]
Prior Period Reclassification Adjustment Balance Sheet		$ 6,800		$ 6,300
[1]	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utility segment to the Gas Utility segment. Accounts receivable of $6.8 million and $6.3 million as of December 31, 2015 and March 31, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

Regulatory Accounting_ Regula57

Regulatory Accounting: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 293,131	$ 232,484	$ 235,477
Regulatory Liabilities		$ 236,270	153,041	166,539
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Liabilities	[1],[2]	$ 40,797	7,814	18,094
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Liabilities	[3],[4]	$ 63,580	47,218	53,151
Cost of removal
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Liabilities	[2]	$ 123,076	90,045	81,449
Other regulatory liabilities
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		25 years
Regulatory Liabilities	[3]	$ 8,817	7,964	13,845
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets	[1],[2]	$ 24,479	24,751	30,833
Deferred gas cost adjustments
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets	[1],[2]	$ 14,895	15,521	6,138
Gas price derivatives
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		7 years
Regulatory Assets	[2]	$ 20,324	23,583	21,606
AFUDC
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		45 years
Regulatory Assets	[5]	$ 13,677	12,870	12,114
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Assets	[3],[4]	$ 111,661	83,986	97,700
Environmental
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	[2]	$ 1,162	1,180	1,240
Asset retirement obligations
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Assets	[2]	$ 487	457	3,237
Bond issue cost
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		22 years
Regulatory Assets	[2]	$ 3,097	3,133	3,240
Renewable energy standard adjustment
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets	[5]	$ 4,507	5,068	5,590
Flow through accounting
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		35 years
Regulatory Assets	[3]	$ 30,614	29,722	26,835
Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		10 years
Regulatory Assets	[6]	$ 18,134	18,310	13,702
Gas Supply Contract Termination
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets		$ 30,613	0	0
Other regulatory assets
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		15 years
Regulatory Assets	[2]	$ 19,481	$ 13,903	$ 13,242
Black Hills Power [Member] | Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	[6]	$ 13,000
[1]	Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.
[2]	Recovery of costs, but we are not allowed a rate of return.
[3]	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.
[4]	Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans.
[5]	In addition to recovery of costs, we are allowed a rate of return.
[6]	South Dakota Electric has approximately $13 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants that are allowed a rate of return, in addition to recovery of costs.

Regulatory Accounting_ Gas Supp

Regulatory Accounting: Gas Supply Contract Termination (Details) - Subsequent Event [Member]	Apr. 30, 2016$ / Btu
Minimum [Member]
Subsequent Event [Line Items]
Oil and Gas Delivery Commitments and Contracts, Fixed Price	6
Maximum [Member]
Subsequent Event [Line Items]
Oil and Gas Delivery Commitments and Contracts, Fixed Price	8

Materials, Supplies and Fuel_59

Materials, Supplies and Fuel: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Inventory, Net [Abstract]
Materials and supplies	$ 66,542	$ 55,726	$ 52,429
Fuel - Electric Utilities	5,365	5,567	6,780
Natural gas in storage held for distribution	6,269	25,650	7,417
Total materials, supplies and fuel	$ 78,176	$ 86,943	$ 66,626

Goodwill & Intangible Assets_60

Goodwill & Intangible Assets: Goodwill (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Goodwill, beginning balance		$ 359,759
Additions		946,410
Goodwill, ending balance		1,306,169
Electric Utilities [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	[1]	250,487
Additions		0
Goodwill, ending balance		250,487
Gas Utilities [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	[1]	100,507
Goodwill, ending balance		1,046,917
Power Generation [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance		8,765
Additions		0
Goodwill, ending balance		8,765
SourceGas Transaction [Member] | Gas Utilities [Member]
Goodwill [Roll Forward]
Additions	[2]	$ 946,410
Goodwill [Member]
Goodwill [Line Items]
Prior Period Reclassification Adjustment Balance Sheet			$ 6,300
[1]	Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details.
[2]	Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

Goodwill & Intangible Assets_ I

Goodwill & Intangible Assets: Intangible Assets (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)
Finite-lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 3,380
Amortization expense	(157)
Intangible assets, net, ending balance	$ 10,957
Source Gas [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	5 years
Finite-lived Intangible Assets [Roll Forward]
Additions, net	$ 7,734	[1]
[1]	Intangible assets, net acquired from SourceGas are primarily trademarks and tradenames, and are amortized over 5-year estimated useful lives. See Note 2 for more information.

Earnings Per Share_ Earnings 62

Earnings Per Share: Earnings Per Share (Details) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net income (loss) available for common stock		$ 40,002	$ 33,850
Weighted average shares - basic		51,044	44,541
Dilutive effect of:
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	[1]	720	0
Equity compensation		94	119
Weighted average shares - diluted		51,858	44,660
[1]	Calculated using the treasury stock method.

Earnings Per Share_ Anti-diluti

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	74	107
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	74	107

Notes Payable_ Notes Payable (D

Notes Payable: Notes Payable (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Revolving Credit Facility [Line Items]
Balance Outstanding	$ 215,600	$ 76,800	$ 102,600
Revolving Credit Facility [Member]
Revolving Credit Facility [Line Items]
Balance Outstanding	215,600	76,800	102,600
Letters of Credit	24,000	$ 33,399	$ 22,300
Current Borrowing Capacity	$ 500,000
Expiration Date	Jun. 26, 2020
Maximum Borrowing Capacity	$ 750,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.175%
Revolving Credit Facility [Member] | Base Rate [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	0.125%
Revolving Credit Facility [Member] | Eurodollar [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.125%
Revolving Credit Facility [Member] | Letter of Credit [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.125%

Notes Payable_ Debt covenants (

Notes Payable: Debt covenants (Details) $ in Thousands	Mar. 31, 2016USD ($)	Feb. 12, 2016USD ($)	Feb. 11, 2016	Jan. 13, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)
Long-term Debt, Gross	$ 3,175,659				$ 1,866,866	$ 1,542,658
Revolving Credit Facility [Member]
Debt instrument, covenant, Leverage Recourse Ratio	0.75
Recourse Leverage Ratio	71.00%
Source Gas [Member]
Long-term Debt, Gross		$ 760,000
Minimum [Member]
Debt instrument, covenant, Leverage Recourse Ratio		0.75	0.65
Debt Instrument, Consolidated Debt to Capitalization Ratio		0.75
Maximum [Member]
Debt instrument, covenant, Leverage Recourse Ratio		1	1
Debt Instrument, Consolidated Debt to Capitalization Ratio		1
Black Hills Corporation [Member]
Long-term Debt, Gross				$ 550,000
Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member]
Long-term Debt, Gross	$ 340,000

Long-Term Debt_ Long-Term Deb66

Long-Term Debt: Long-Term Debt (Details) - USD ($) $ in Thousands		Mar. 31, 2016		Jan. 13, 2016	Dec. 31, 2015		Mar. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 3,175,659			$ 1,866,866		$ 1,542,658
Current maturities of long-term debt		0			0		0
Deferred Finance Costs, Net		(16,604)			(13,184)		(11,286)
Long-term Debt, Excluding Current Maturities		3,159,055			1,853,682		1,531,372
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Net		(1,600)			(1,700)		(1,600)
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross				$ 550,000
Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.95%
Long-term Debt, Gross				$ 300,000
Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				2.50%
Long-term Debt, Gross				$ 250,000
Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		340,000
Gas Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 419,897			0		0
Gas Utilities [Member] | Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[1],[2]	3.98%
Long-term Debt, Gross		$ 95,000	[1],[2]		0		0
Gas Utilities [Member] | Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.90%
Long-term Debt, Gross		$ 325,000	[2]		0		0
Debt Instrument, Unamortized Discount		(103)			0		0
Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 544,758			544,756		544,753
Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.43%
Long-term Debt, Gross		$ 85,000			85,000		85,000
Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.53%
Long-term Debt, Gross		$ 75,000			75,000		75,000
Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		7.23%
Long-term Debt, Gross		$ 75,000			75,000		75,000
Electric Utilities [Member] | First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.13%
Long-term Debt, Gross		$ 180,000			180,000		180,000
Debt Instrument, Unamortized Discount		$ (97)			(99)		(102)
Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.67%
Long-term Debt, Gross		$ 110,000			110,000		110,000
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[3]	$ 7,000			7,000		7,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[3]	0.45%
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[3]	$ 10,000			10,000		10,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[3]	0.47%
Electric Utilities [Member] | Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[3]	$ 2,855			2,855		2,855
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[3]	0.85%
Corporate[Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,211,004			1,322,110		997,905
Corporate[Member] | Remarketable Junior Subordinated Notes Due 2028 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.50%
Long-term Debt, Gross		$ 299,000			299,000		0
Corporate[Member] | Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.95%
Long-term Debt, Gross		$ 300,000			0		0
Debt Instrument, Unamortized Discount		$ (892)			0		0
Corporate[Member] | Senior Unsecured Notes Due 2023 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.25%
Long-term Debt, Gross		$ 525,000			525,000		525,000
Debt Instrument, Unamortized Discount		$ (1,822)			(1,890)		(2,095)
Corporate[Member] | Senior Unsecured Notes Due 2020 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.88%
Long-term Debt, Gross		$ 200,000			200,000		200,000
Corporate[Member] | Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.50%
Long-term Debt, Gross		$ 250,000			0		0
Debt Instrument, Unamortized Discount		(282)			0		0
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2017 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 340,000	[2],[3]		0		0
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[2],[3]	1.38%
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due April 2017 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 300,000	[3]		300,000	[3]	0
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[3]	1.40%
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2015 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 0			$ 0		$ 275,000	[3]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[3]	1.31%
[1]	Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness.
[2]	Long-term debt assumed with the SourceGas Acquisition.
[3]	Variable interest rate, based on LIBOR plus a spread.

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Long-term Debt, Unclassified [Abstract]
2,016	$ 0	$ 0	$ 0
2,017	965,000
2,018	0
2,019	345,000
2,020	200,000
Thereafter	$ 1,668,855

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands	Jan. 13, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 3,175,659	$ 1,542,658	$ 1,866,866
Long-term debt - issuances	$ 546,000	$ 545,959	$ 0
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	550,000
Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 300,000
Debt Instrument, Interest Rate, Stated Percentage	3.95%
Debt Instrument, Term	10 years
Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 250,000
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Term	3 years

Long-Term Debt_ Assumption of B

Long-Term Debt: Assumption of Black Hills Holdings LTD (Details) - USD ($) $ in Thousands		Mar. 31, 2016		Feb. 12, 2016	Jan. 13, 2016	Dec. 31, 2015	Mar. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 3,175,659				$ 1,866,866	$ 1,542,658
Source Gas [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross				$ 760,000
Gas Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		419,897				0	0
Senior Unsecured Notes Due 2017 [Member] | Gas Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 325,000	[1]			0	0
Debt Instrument, Interest Rate, Stated Percentage	[1]	5.90%
Senior Unsecured Notes Due 2017 [Member] | Gas Utilities [Member] | Source Gas [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1]			$ 325,000
Debt Instrument, Interest Rate, Stated Percentage	[1]			5.90%
Senior Secured Notes due 2019 [Member] | Gas Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 95,000	[1],[2]			$ 0	$ 0
Debt Instrument, Interest Rate, Stated Percentage	[1],[2]	3.98%
Senior Secured Notes due 2019 [Member] | Gas Utilities [Member] | Source Gas [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1],[2]			$ 95,000
Debt Instrument, Interest Rate, Stated Percentage	[1],[2]			3.98%
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross					$ 550,000
Black Hills Corporation [Member] | Corporate Term Loan Due June 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 340,000
Black Hills Corporation [Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2017 [Member] | Source Gas [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	[1],[3]			$ 340,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[1],[3]			0.875%
[1]	Long-term debt assumed with the SourceGas Acquisition.
[2]	Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness.
[3]	Variable interest rate, based on LIBOR plus a spread.

Equity_ Equity (Details)

Equity: Equity (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, beginning balance	$ 1,465,867	$ 1,353,884
Net income (loss) available for common stock	40,002	33,850
Other comprehensive income	(11,770)	990
Dividends on common stock	(21,543)	(18,148)
Share-based compensation	561	209
Issuance of common stock	6,824	0
Dividend reinvestment and stock purchase plan	755	798
Other stock transactions	(13)	0
Stockholders' Equity, ending balance	$ 1,480,683	$ 1,371,583

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Thousands	Apr. 05, 2016	Mar. 31, 2016	Mar. 31, 2015	Mar. 18, 2016
At The Market Equity Offering Program Authorized Aggregate Value				$ 200,000
Issuance of common stock		$ 6,824	$ 0
Payments of Stock Issuance Costs		$ 100
Common Stock [Member]
At The Market Equity Offering Program Shares Issued		121,000
At the Market Equity Program - Proceeds From Sale of Stock		$ 7,000
Subsequent Event [Member] | Common Stock [Member]
At The Market Equity Offering Program Shares Issued	140,000
At the Market Equity Program - Proceeds From Sale of Stock	$ 8,400

Risk Management Activities_ R72

Risk Management Activities: Risk Management Activities (Details) $ in Thousands		3 Months Ended			12 Months Ended
		Mar. 31, 2016USD ($)MMBTUbbl		Mar. 31, 2015USD ($)MMBTUbbl	Dec. 31, 2015USD ($)MMBTUbbl
Derivative [Line Items]
Derivative assets, current		$ 1,486		$ 0	$ 0
Derivative assets, non-current		85		0	3,441
Derivative liabilities, current		3,965		3,342	2,835
Derivative liabilities, non-current		14,522		$ 2,143	$ 156
Oil and Gas [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months		7,600
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net		$ (2,300)
Crude Oil [Member] | Swaps and Options [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities | bbl	[1]	159,000		305,000	198,000
Maximum Term Hedged in Cash Flow Hedge	[2]	1 month		1 month	1 month
Derivative assets, current		$ 0		$ 0	$ 0
Derivative assets, non-current		0		0	0
Derivative liabilities, current		0		0	0
Derivative liabilities, non-current		$ 0		$ 0	$ 0
Natural Gas [Member] | Swap [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU	[1]	3,447,500		5,367,500	4,392,500
Maximum Term Hedged in Cash Flow Hedge	[2]	1 month		1 month	1 month
Derivative assets, current		$ 0		$ 0	$ 0
Derivative assets, non-current		0		0	0
Derivative liabilities, current		0		0	0
Derivative liabilities, non-current		0		0	0
Natural Gas, Distribution [Member]
Derivative [Line Items]
Derivative assets, current		1,486		0	0
Derivative assets, non-current		85		0	0
Derivative liabilities, current		1,675		0	0
Derivative liabilities, non-current		44		0	0
Net Unrealized (Gain) Loss Included in Regulatory assets or Regulatory liabilities		$ 20,324		$ 21,606	$ 23,578
Natural Gas, Distribution [Member] | Future [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		18,270,000		17,280,000	20,580,000
Maximum Term	[3]	57 months		69 months	60 months
Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		990,000		1,320,000	2,620,000
Maximum Term	[3]	21 months		12 months	3 months
Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		16,810,000		15,735,000	18,150,000
Maximum Term	[3]	57 months		57 months	60 months
Natural Gas, Distribution [Member] | Fixed for Float Swaps Purchased [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		2,374,000	[4]	0	0
Maximum Term	[3]	23 months		0 months	0 months
Natural Gas, Distribution [Member] | Fixed For Float Swaps Sold [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		816,989	[4]	0	0
Maximum Term	[3]	15 months		0 months	0 months
Natural Gas, Distribution [Member] | Natural Gas Physical Purchases [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		2,948,250		0	0
Maximum Term	[3]	12 months		0 months	0 months
Natural Gas, Distribution [Member] | Natural Gas Physical Sales [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		813,200		0	0
Maximum Term	[3]	11 months		0 months	0 months
Revolving Credit Facility [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, non-current		$ 0		$ 0	$ 0
Derivative liabilities, current		2,290		3,342	2,835
Derivative liabilities, non-current		0		2,143	156
Notional Amount	[5]	$ 75,000		$ 75,000	$ 75,000
Weighted average fixed interest rate		4.97%		4.97%	4.97%
Maximum Term		9 months		1 year 9 months	1 year
Cash Flow Hedging [Member] | Natural Gas, Distribution [Member] | Fixed for Float Swaps Purchased [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU	[4]	1,109,500
Cash Flow Hedging [Member] | Natural Gas, Distribution [Member] | Fixed For Float Swaps Sold [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU	[4]	112,500
Interest Rate Swap One [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, non-current		$ 0			$ 3,441
Derivative liabilities, current		0			0
Derivative liabilities, non-current		10,693			0
Notional Amount	[6]	$ 250,000			$ 250,000
Weighted average fixed interest rate		2.29%			2.29%
Maximum Term		1 year 1 month			1 year 4 months
Interest Rate Swap Two [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, non-current		$ 0
Derivative liabilities, current		0
Derivative liabilities, non-current		3,785
Notional Amount	[6]	$ 150,000
Weighted average fixed interest rate		2.09%
Maximum Term		1 year 1 month
[1]	Crude oil in Bbls, natural gas in MMBtus.
[2]	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
[3]	Term reflects the maximum forward period hedged.
[4]	1,109,500 MMBtus and 112,500 MMBtus were designated as cash flow hedges for the natural gas swaps purchased and sold, respectively.
[5]	These swaps are designated to borrowings on our Revolving Credit Facility and are priced using three-month LIBOR, matching the floating portion of the related borrowings.
[6]	These swaps are designated as cash flow hedges of anticipated debt refinancings.

Risk Management Activities_ Hed

Risk Management Activities: Hedging Activities (Details) - Cash Flow Hedging [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	$ (13,220)	$ 2,878
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	5,358	(2,495)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(15,047)	(886)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	1,709	1,437
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		3,764
Commodity Contract [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	1,589
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	3,592	(3,932)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	$ 0
Commodity Contract [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	238
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	57
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 0

Fair Value Measurements_ Fair74

Fair Value Measurements: Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Assets-Transfers out of level 1 to 2	$ 0	$ 0	$ 0
Assets -Transfers out of level 2 to 1	0	0	0
Liabilities -Transfers out of level 1 to 2	0	0	0
Liabilities -Transfers out of level 2 to 1	0	0	0
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(9,928)	(12,937)	(15,806)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(21,959)	(25,141)	(22,260)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	11,499	16,378	15,806
Derivative Liabilities, Total	40,446	28,132	27,745
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	3,441	0
Derivative Liabilities, Fair Value Disclosure	16,768	2,991	5,485
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(4,668)	(6,309)	(8,096)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	(2)
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	4,668	6,309	8,096
Derivative Liabilities, Fair Value Disclosure	0	0	2
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(3,761)	(4,335)	(6,526)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(250)	(556)	(256)
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	3,761	4,335	6,526
Derivative Liabilities, Fair Value Disclosure	250	556	256
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,499)	(2,293)	(1,184)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(21,709)	(24,585)	(22,002)
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	3,070	2,293	1,184
Derivative Liabilities, Fair Value Disclosure	23,428	24,585	22,002
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	1,571	3,441	0
Derivative Liabilities, Total	18,487	2,991	5,485
Estimate of Fair Value Measurement [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	3,441	0
Derivative Liabilities, Fair Value Disclosure	16,768	2,991	5,485
Estimate of Fair Value Measurement [Member] | Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Estimate of Fair Value Measurement [Member] | Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	1,571	0	0
Derivative Liabilities, Fair Value Disclosure	$ 1,719	$ 0	$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 8,593	$ 14,085	$ 14,622
Derivative Liability, Fair Value, Net	17,821	3,547	5,743
Not Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	1,405	0	0
Derivative Liability, Fair Value, Net	21,126	22,292	20,818
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,986	9,981	9,989
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	607	663	4,633
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	982	465	126
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	71	91	132
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,326	0	0
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	79	0	0
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	9,117	9,586	7,530
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	12,009	12,706	13,288
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	3,441	0
Derivative Asset, Fair Value, Gross Liability	0	0	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	2,290	2,835	3,342
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	$ 14,478	$ 156	$ 2,143

Fair Value of Financial Instr76

Fair Value of Financial Instruments: Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents		$ 46,974	$ 456,535	$ 63,385	$ 21,218
Restricted cash and equivalents		1,839	1,697	2,191
Notes payable		215,600	76,800	102,600
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents		46,974	456,535	63,385
Restricted cash and equivalents		1,839	1,697	2,191
Notes payable		215,600	76,800	102,600
Long-term debt, including current maturities		3,159,055	1,853,682	1,531,372
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	[1]	46,974	456,535	63,385
Restricted Cash Fair Value Disclosure	[1]	1,839	1,697	2,191
Notes payable, Fair Value	[1]	215,600	76,800	102,600
Long-term debt, including current maturities, Fair Value	[2]	$ 3,392,652	$ 1,992,274	$ 1,767,113
[1]	Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.
[2]	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Other Comprehensive Income (L77

Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 32,074	$ 19,910
Revenue	449,959	441,987
Fuel, purchased power and cost of natural gas sold	(171,856)	(205,327)
Operations and maintenance	107,062	93,134
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	44,302	51,859
Income tax benefit (expense)	(4,252)	(17,712)
Net income (loss)	40,050	33,850
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(5,358)	(2,495)
Income tax benefit (expense)	1,946	1,254
Net income (loss)	(3,412)	(1,241)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(1,709)	1,437
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Commodity Contract [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Revenue	(3,592)	(3,932)
Fuel, purchased power and cost of natural gas sold	(57)	0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	(55)	(55)
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	494	705
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	439	650
Income tax benefit (expense)	(153)	(228)
Net income (loss)	$ 286	$ 422

Other Comprehensive Income (L78

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (9,055)	$ (15,044)
Other comprehensive income (loss), net of tax	(11,770)	990
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(20,825)	(14,054)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	6,725	5,093
Other comprehensive income (loss), net of tax	(12,056)	595
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(5,331)	5,688
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(15,780)	(20,137)
Other comprehensive income (loss), net of tax	286	395
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (15,494)	$ (19,742)

Supplemental Disclosure of Ca79

Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 30,260	$ 33,534
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(15,528)	(10,909)
Income taxes, net	$ 0	$ (2)

Employee Benefit Plans_ Emplo80

Employee Benefit Plans: Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 2,800
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	2,078	$ 1,494
Interest Cost	3,936	3,880
Expected return on plan assets	(5,765)	(4,867)
Prior service cost (benefit)	15	15
Net loss (gain)	1,793	2,759
Net periodic benefit cost	2,057	3,281
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	0
Estimated Future Employer Contributions in Current Fiscal Year	10,200
Estimated Future Employer Contributions in Next Fiscal Year	10,200
Other Pension Plan, Postretirement or Supplemental Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	300
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	29	491
Interest Cost	314	364
Prior service cost (benefit)	0	1
Net loss (gain)	207	270
Net periodic benefit cost	550	1,126
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	392
Estimated Future Employer Contributions in Current Fiscal Year	1,176
Estimated Future Employer Contributions in Next Fiscal Year	1,627
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	400
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	467	464
Interest Cost	485	450
Expected return on plan assets	(70)	(33)
Prior service cost (benefit)	(107)	(107)
Net loss (gain)	84	102
Net periodic benefit cost	859	$ 876
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	1,192
Estimated Future Employer Contributions in Current Fiscal Year	3,576
Estimated Future Employer Contributions in Next Fiscal Year	$ 4,744
Source Gas [Member] | Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan			$ 22,187
Source Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan			$ 11,751
Interest Cost [Member] | Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.827%
Interest Cost [Member] | Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.817%
Interest Cost [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.284%
Interest Cost [Member] | Source Gas [Member] | Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.69%
Interest Cost [Member] | Source Gas [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.319%
Scenario, Previously Reported [Member] | Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.575%
Scenario, Previously Reported [Member] | Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.50%
Scenario, Previously Reported [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.165%

Commitments and Contingencies81

Commitments and Contingencies: Supply Commitments (Details) - Source Gas [Member] $ in Thousands	Mar. 31, 2016USD ($)
2,016	$ 38,817
2,017	47,464
2,018	46,641
2,019	42,312
2,020	41,995
Thereafter	195,977
Total	413,206
Facilities and equipment [Member]
2,016	1,755
2,017	2,216
2,018	2,207
2,019	1,676
2,020	1,359
Thereafter	3,326
Total	12,539
Pipeline capacity obligations [Member]
2,016	37,062
2,017	45,248
2,018	44,434
2,019	40,636
2,020	40,636
Thereafter	192,651
Total	$ 400,667

Commitments and Contingencies82

Commitments and Contingencies: Build Transfer Agreement (Details) - Peak View Wind Project [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Long-term Purchase Commitment, Amount	$ 109
Electric Utilities [Member] | Performance Guarantee [Member]
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 85

Commitments and Contingencies83

Commitments and Contingencies: Commitments and Contingencies - Dividend Restrictions (Details) $ in Millions	Mar. 31, 2016USD ($)
Utilities Group [Member]
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Impairment of Assets_ Impairmen

Impairment of Assets: Impairment of Long-lived assets (Details) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Mar. 31, 2016$ / bbl$ / MMcf	Dec. 31, 2015USD ($)	Mar. 31, 2015$ / bbl$ / MMcf
Impairment of Oil and Gas Properties | $	$ 14,496	$ 22,036
Oil and Gas [Member]
Impairment of Oil and Gas Properties | $	$ 14,000	$ 22,000		$ 250,000
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf			2.40		3.88
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf			1.13		2.69
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl			46.26		82.72
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl			39.80		74.13

Income Taxes_ Income Taxes (Det

Income Taxes: Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016		Mar. 31, 2015
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	35.00%		35.00%
State income tax (net of federal tax effect)	2.60%		1.20%
Percentage depletion in excess of cost	(14.10%)	[1]	(1.00%)
Accounting for uncertain tax positions adjustment	(11.40%)	[2]	1.90%
Inter-period tax allocation	(4.00%)		(1.50%)
Transaction costs	2.50%		0.00%
Other tax differences	(1.00%)		(1.20%)
Effective Tax Rate	9.60%		34.40%
IRS Settlement [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	$ 26
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 11
[1]	The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties and represents a change in estimate for income tax accounting purposes. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.
[2]	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 after-tax interest expense and tax credits that were previously accrued 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.

Accrued Liabilities_ Accrued 86

Accrued Liabilities: Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 90,295	$ 43,342	$ 32,090
Accrued property taxes	40,638	32,393	32,835
Accrued payments related to litigation expenses and settlements	0	38,750	25,000
Gas-gathering contract	39,944	0	0
Customer deposits and prepayments	26,042	53,496	16,210
Accrued interest and contract adjustment payments	43,119	25,762	21,559
CIAC current portion	20,466	14,745	0
Other (none of which is individually significant)	11,677	23,573	39,087
Total accrued liabilities	$ 272,181	$ 232,061	$ 166,781

Subsequent Event_ Settlement of

Subsequent Event: Settlement of Gas Supply Contract (Details) - Subsequent Event [Member] $ in Millions	Apr. 29, 2016USD ($)	Apr. 30, 2016$ / Btu
Subsequent Event [Line Items]
Early Termination / Settlement Of Gas Supply Contract | $	$ 40
Minimum [Member]
Subsequent Event [Line Items]
Oil and Gas Delivery Commitments and Contracts, Fixed Price		6
Maximum [Member]
Subsequent Event [Line Items]
Oil and Gas Delivery Commitments and Contracts, Fixed Price		8

Subsequent Event_ Sale of Non-c

Subsequent Event: Sale of Non-controlling Interest in Subsidiary (Details) - USD ($) $ in Millions	Apr. 14, 2016	Mar. 31, 2016
Subsequent Event [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		0.50%
Subsequent Event [Member]
Subsequent Event [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.90%
Proceeds from Divestiture of Businesses	$ 215
Controlling Interest, Ownership Percentage by Controlling Owners	50.10%