Black Hills (BKH) 10-Q 5 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2016	Jul. 31, 2016
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		52,324,123
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			6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Revenue	$ 325,441	$ 272,254		$ 775,400	$ 714,241
Operating expenses:
Fuel, purchased power and cost of natural gas sold	84,489	73,824		256,345	279,151
Operations and maintenance	112,541	90,410		219,603	183,544
Depreciation, depletion and amortization	47,305	40,051		91,712	79,053
Taxes - property, production and severance	12,760	11,377		24,877	23,313
Impairment of long-lived assets	25,497	94,484		39,993	116,520
Other operating expenses	7,551	966		33,982	1,018
Total operating expenses	290,143	311,112		666,512	682,599
Operating income (loss)	35,298	(38,858)		108,888	31,642
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(34,609)	(19,545)		(66,683)	(39,455)
Allowance for funds used during construction - borrowed	754	207		1,255	365
Capitalized interest	268	481		503	757
Interest income	946	301		1,601	749
Allowance for funds used during construction - equity	982	77		1,689	133
Other income (expense), net	(47)	395		641	726
Total other income (expense), net	(31,706)	(18,084)		(60,994)	(36,725)
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	3,592	(56,942)		47,894	(5,083)
Equity in earnings (loss) of unconsolidated subsidiaries	0	(47)		0	(344)
Equity Method Investment, Other than Temporary Impairment	0	(5,170)		0	(5,170)
Income tax benefit (expense)	(309)	20,317		(4,561)	2,605
Net income (loss)	3,283	(41,842)		43,333	(7,992)
Net income attributable to non-controlling interest	(2,614)	0		(2,662)	0
Net income (loss) available for common stock	$ 669	$ (41,842)		$ 40,671	$ (7,992)
Earnings Per Share, Basic [Abstract]
Earnings (loss) per share, Basic (usd per share)	$ 0.01	$ (0.94)		$ 0.79	$ (0.18)
Earnings Per Share, Diluted [Abstract]
Earnings (loss) per share, Diluted (usd per share)	$ 0.01	$ (0.94)		$ 0.78	$ (0.18)
Weighted average common shares outstanding:
Basic (in shares)	51,514	44,617		51,279	44,579
Diluted (in shares)	52,986	44,617	[1]	52,454	44,579	[1]
Dividends declared per share of common stock (usd per share)	$ 0.420	$ 0.405		$ 0.840	$ 0.810
[1]	Due to our net loss for the three and six months ended June 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 83,613 and 101,146 equity compensation shares were excluded from the computations for the three and six months ended June 30, 2015, respectively.

Condensed Consolidated Stateme3

Condensed Consolidated Statement of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 3,283	$ (41,842)	$ 43,333	$ (7,992)
Other comprehensive income (loss), net of tax:
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $5,346 and $1,171 for the three months ended 2016 and 2015 and $10,865 and $128 for the six months ended 2016 and 2015, respectively)	(9,720)	(1,966)	(20,066)	(130)
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $882 and $735 for the three months ended 2016 and 2015 and $1,884 and $1,989 for the six months ended 2016 and 2015, respectively)	(1,504)	(1,261)	(3,214)	(2,502)
Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $0 and $0 for the three months ended 2016 and 2015 and $0 and $15 for the six months ended 2016 and 2015, respectively)	0	0	0	(27)
Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $19 for the three months ended 2016 and 2015 and $38 and $38 for the six months ended 2016 and 2015, respectively)	(36)	(36)	(72)	(72)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(173) and $(247) for the three months ended 2016 and 2015 and $(346) and $(494) for the six months ended 2016 and 2015, respectively)	321	458	643	916
Other comprehensive income (loss), net of tax	(10,939)	(2,805)	(22,709)	(1,815)
Comprehensive income (loss)	(7,656)	(44,647)	20,624	(9,807)
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	(2,614)	0	(2,662)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (10,270)	$ (44,647)	$ 17,962	$ (9,807)

Condensed Consolidated Stateme4

Condensed Consolidated Statement of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Fair value adjustment on derivatives designated as cash flow hedges, (tax) benefit	$ 5,346	$ 1,171	$ 10,865	$ 128
Reclassification adjustments of cash flow hedges settled and included in net income, (tax) benefit	882	735	1,884	1,989
Benefit plan liability adjustments net gain, (tax) benefit	0	0	0	15
Reclassification adjustment of benefit plan prior service cost included in net income, (tax) benefit	19	19	38	38
Reclassification adjustment of benefit plan liabilities actuarial gain (loss), (tax) benefit	$ (173)	$ (247)	$ (346)	$ (494)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Current assets:
Cash and cash equivalents	$ 116,805	$ 456,535	$ 87,210
Restricted cash and equivalents	1,975	1,697	2,316
Accounts receivable, net	150,227	147,486	123,661
Materials, supplies and fuel	85,189	86,943	73,749
Derivative assets, current	4,030	0	0
Income tax receivable, net	0	368	770
Deferred income tax assets, net, current	0	0	52,394
Regulatory assets, current	54,856	57,359	47,157
Other current assets	30,652	71,763	51,315
Total current assets	443,734	822,151	438,572
Investments	12,363	11,985	12,098
Property, plant and equipment	6,209,816	4,976,778	4,726,478
Less: accumulated depreciation and depletion	(1,819,886)	(1,717,684)	(1,522,969)
Total property, plant and equipment, net	4,389,930	3,259,094	3,203,509
Other assets:
Goodwill	1,303,453	359,759	353,396
Intangible assets, net	9,164	3,380	3,211
Regulatory assets, non-current	220,556	175,125	180,815
Derivative assets, non-current	226	3,441	0
Other assets, non-current	15,438	7,382	17,313
Total other assets, non-current	1,548,837	549,087	554,735
TOTAL ASSETS	6,394,864	4,642,317	4,208,914
Current liabilities:
Accounts payable	170,149	105,468	78,021
Accrued liabilities	218,250	232,061	160,528
Derivative liabilities, current	28,855	2,835	3,289
Accrued Income Taxes	10,624	0	0
Regulatory liabilities, current	34,275	4,865	10,910
Notes payable	75,000	76,800	105,760
Long-term Debt, Current Maturities	930,743	0	0
Total current liabilities	1,467,896	422,029	358,508
Long-term debt, net of current maturities	2,221,347	1,853,682	1,556,370
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	530,746	450,579	510,435
Derivative liabilities, non-current	231	156	1,433
Regulatory liabilities, non-current	195,166	148,176	150,835
Benefit plan liabilities	173,347	146,459	165,791
Other deferred credits and other liabilities	122,015	155,369	154,656
Total deferred credits and other liabilities	1,021,505	900,739	983,150
Commitments and contingencies (See Notes 9, 10, 11, 17, 18)
Redeemable noncontrolling interest	4,171	0	0
Stockholders’ equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 52,299,075; 51,231,861; and 44,871,771 shares, respectively	52,299	51,232	44,872
Additional Paid in Capital	1,072,927	953,044	751,679
Retained earnings	469,940	472,534	532,965
Treasury stock, at cost – 18,900; 39,720; and 35,855 shares, respectively	(975)	(1,888)	(1,771)
Accumulated other comprehensive income (loss)	(31,764)	(9,055)	(16,859)
Stockholders' Equity Attributable to Parent	1,562,427	1,465,867	1,310,886
Noncontrolling Interest in Variable Interest Entity	117,518	0	0
Total stockholders’ equity	1,679,945	1,465,867	1,310,886
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 6,394,864	$ 4,642,317	$ 4,208,914

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (unaudited) Condensed Consolidated Balance Sheets (Parentheticals) - $ / shares	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	52,299,075	51,231,861	44,871,771
Treasury Stock, Shares	18,900	39,720	35,855
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	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating activities:
Net income (loss) available for common stock	$ 40,671	$ (7,992)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	91,712	79,053
Deferred financing cost amortization	2,857	1,119
Impairment of long-lived assets	39,993	121,690
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(4,617)	(5,249)
Stock compensation	7,054	3,098
Deferred income taxes	32,606	(6,277)
Employee benefit plans	7,782	10,467
Other adjustments, net	(1,715)	3,720
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	17,722	20,218
Accounts receivable, unbilled revenues and other operating assets	82,361	63,172
Accounts payable and other operating liabilities	(85,423)	(66,294)
Regulatory assets - current	1,862	27,178
Regulatory liabilities - current	2,994	7,290
Pension Contributions	(10,200)	0
Other operating activities, net	(2,884)	3,215
Net cash provided by (used in) operating activities	222,775	254,408
Investing activities:
Property, plant and equipment additions	(199,854)	(206,472)
Acquisition, net of long term debt assumed	(1,124,238)	0
Other investing activities	(649)	(652)
Net cash provided by (used in) investing activities	(1,324,741)	(207,124)
Financing activities:
Dividends paid on common stock	(43,265)	(36,292)
Common stock issued	57,490	1,702
Sale of noncontrolling interest	216,370	0
Short-term borrowings - issuances	208,100	154,460
Short-term borrowings - repayments	(209,900)	(123,700)
Long-term debt - issuances	574,672	300,000
Repayments of Long-term Debt	(41,436)	(275,000)
Other financing activities	205	(2,462)
Net cash provided by (used in) financing activities	762,236	18,708
Net change in cash and cash equivalents	(339,730)	65,992
Cash and Cash Equivalents
Cash and cash equivalents, beginning of period	456,535	21,218
Cash and cash equivalents, end of period	$ 116,805	$ 87,210

Management's Statement_

Management's Statement:	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Statement	MANAGEMENT’S STATEMENT The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2015 Annual Report on Form 10-K filed with the SEC. Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. In 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 and six months ended June 30, 2015 , respectively: For the Three Months Ended June 30, 2015 For the Six Months Ended June 30, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 67,264 $ (67,264 ) $ — $ 138,348 $ (138,348 ) $ — Non-regulated energy operations and maintenance $ 23,146 $ (23,146 ) $ — $ 45,196 $ (45,196 ) $ — Operations and maintenance $ — $ 90,410 $ 90,410 $ — $ 183,544 $ 183,544 This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows. Segment reporting transition of Cheyenne Light’s natural gas distribution Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015 , Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior period has been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 3 for Revenues, Net Income and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the three and six months ending June 30, 2015 . This segment reclassification did not impact our consolidated financial position, results of operations or cash flows. Use of estimates and basis of presentation Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2016 , December 31, 2015 , and June 30, 2015 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2016 and June 30, 2015 , and our financial condition as of June 30, 2016 , December 31, 2015 , and June 30, 2015 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Significant Accounting Policies Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. 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. Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 11 for additional detail on Noncontrolling Interests. 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, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. The Company is currently assessing the impact that adoption of ASU 2016-09 will have on its consolidated financial position, results of operations and cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASC is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations and cash flows. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We are currently assessing the impact that adoption of ASU 2014-09 will have on our financial position, results of operations and cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent) . The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs . Debt issuance costs related to a recognized debt liability are presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of June 30, 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 June 30, 2015, respectively. Adoption of ASU 2015-03 did not have a material impact on our financial position. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments . This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on the Company’s financial position, results of operations and cash flows.

Acquisition_

Acquisition:	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Acquisition	ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock and 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, the Company recorded pre-tax acquisition costs of approximately $6.3 million and $31 million , respectively, in the three and six months ended June 30, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Condensed Consolidating Income Statements. There were $0.7 million of acquisition costs recorded in the three and six months ended June 30, 2015. Our consolidated operating results for the three and six months ended June 30, 2016 include revenues of $70 million and $145 million , respectively, and net income (loss) of $(3.0) million and $4.6 million , respectively, attributable to SourceGas for the period from February 12 through June 30, 2016. SourceGas is reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. We are still determining the purchase price allocation for SourceGas. A preliminary purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion , net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million , resulted in a preliminary estimate of goodwill totaling $944 million . This estimate is subject to change and will likely result in an increase or decrease in goodwill, which could be material. We have up to one year from the acquisition date to finalize the purchase price allocation. During the three months ended June 30, 2016, we decreased goodwill by $2.7 million , reflecting the working capital adjustment received of $11 million and changes in valuation estimates for property, plant and equipment, long-term debt and regulatory liabilities. Approximately $214 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities. (in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration Paid, net of working capital adjustment received $ 1,124,238 Preliminary Allocation of Purchase Price: Current Assets $ 111,629 Property, plant & equipment, net 1,047,584 Goodwill 943,694 Deferred charges and other assets, excluding goodwill 132,534 Current liabilities (167,613 ) Long-term debt (764,337 ) Deferred credits and other liabilities (179,253 ) Total preliminary consideration paid, net of working-capital adjustment received $ 1,124,238 Conditions of SourceGas Acquisition Regulatory Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below: The APSC order includes a 12 month base rate moratorium, an annual $0.25 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The CPUC order includes a two -year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three -year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five -years or until we file the next rate case, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The NPSC order includes a three -year base rate moratorium, a three -year continuation of the Choice Gas program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The WPSC order includes a three -year continuation of the Choice Gas program, as well as various other terms and reporting requirements. All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska, however Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs. Settlement of Gas Supply Contract On April 29, 2016, we settled for $40 million , a former SourceGas contract that required the company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. 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 varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing 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. This liability is included with Current liabilities of the preliminary purchase price allocation. Pro Forma Results We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the three and six months ended June 30, 2016 and 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Revenue $ 325,441 $ 347,085 $ 854,362 $ 975,549 Net income (loss) available for common stock $ 4,658 $ (49,751 ) $ 72,978 $ 306 Earnings (loss) per share, Basic $ 0.09 $ (0.98 ) $ 1.42 $ 0.01 Earnings (loss) per share, Diluted $ 0.09 $ (0.98 ) $ 1.39 $ 0.01 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 and six months ended June 30, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the Acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three and six months ended June 30, 2016 reflect unfavorable weather impacts resulting in lower gas pricing than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37% . These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future. Seller’s noncontrolling interest One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas transaction. If we choose not to exercise this option during a ninety-day period, the seller is provided a put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying condensed consolidated balance sheets.

Business Segment Information_

Business Segment Information:	6 Months Ended
	Jun. 30, 2016
Segment Reporting Information, Additional Information [Abstract]
Business Segment Information	BUSINESS SEGMENT INFORMATION Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 158,560 $ 2,921 $ 19,229 Gas 153,767 (1,806 ) 987 Power Generation (e) 1,546 20,168 5,683 Mining 3,922 7,125 724 Oil and Gas (a) 7,646 — (19,424 ) Corporate activities (c) — — (6,530 ) Inter-company eliminations — (28,408 ) — Total $ 325,441 $ — $ 669 Three Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 161,514 $ 2,509 17,632 Gas (d) 87,663 — 3,235 Power Generation 1,706 20,603 7,549 Mining 9,052 7,673 3,049 Oil and Gas (a) (b) 12,319 — (71,195 ) Corporate activities — — (2,112 ) Inter-company eliminations — (30,785 ) — Total $ 272,254 $ — $ (41,842 ) Six Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 322,091 $ 6,666 $ 38,444 Gas 422,434 — 32,914 Power Generation (e) 3,398 41,624 14,265 Mining 11,456 15,873 3,662 Oil and Gas (a) 16,021 — (26,448 ) Corporate activities (c) — — (22,166 ) Inter-company eliminations — (64,163 ) — Total $ 775,400 $ — $ 40,671 Six Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) 328,007 5,933 35,185 Gas (d) 341,795 — 26,823 Power Generation 3,659 41,324 15,694 Mining 17,194 15,465 6,059 Oil and Gas (a) (b) 23,586 — (90,310 ) Corporate activities — — (1,443 ) Inter-company eliminations — (62,722 ) — Total $ 714,241 $ — $ (7,992 ) ___________ (a) Net income (loss) available for common stock for the three and six months ended June 30, 2016 and June 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $16 million and $25 million and $63 million and $77 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) available for common stock for the three and six months ended June 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million . See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Net income (loss) available for common stock for the three and six months ended June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $4.1 million and $20 million , respectively, and after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million , respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $8.2 million and $25 million , respectively, and Net income of $0.1 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (e) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $2.6 million for the three and six months ended June 30, 2016. Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: June 30, 2016 December 31, 2015 June 30, 2015 Segment: Electric (a) (b) $ 2,777,142 $ 2,720,004 $ 2,732,663 Gas (b) 3,142,293 999,778 920,624 Power Generation (a) 80,360 60,864 72,270 Mining 71,319 76,357 76,079 Oil and Gas (c) 171,228 208,956 275,068 Corporate activities (d) 152,522 576,358 132,210 Total assets $ 6,394,864 $ 4,642,317 $ 4,208,914 __________ (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 six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $119 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 June 30, 2015. (c) As a result of continued low commodity prices and the transition of Oil and Gas to support Cost of Service Gas programs, we recorded non-cash impairments of $40 million for the six months ended June 30, 2016 , $250 million for the year ended December 31, 2015, and $117 million for the six months ended June 30, 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:	6 Months Ended
	Jun. 30, 2016
Receivables [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts June 30, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 40,991 $ 34,174 $ (716 ) $ 74,449 Gas Utilities 47,600 23,124 (2,997 ) 67,727 Power Generation 1,229 — — 1,229 Mining 1,114 — — 1,114 Oil and Gas 3,094 — (13 ) 3,081 Corporate 2,627 — — 2,627 Total $ 96,655 $ 57,298 $ (3,726 ) $ 150,227 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 June 30, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 44,126 $ 32,660 $ (746 ) $ 76,040 Gas Utilities (a) 27,890 10,259 (1,198 ) 36,951 Power Generation 1,199 — — 1,199 Mining 3,402 — — 3,402 Oil and Gas 5,099 — (13 ) 5,086 Corporate 983 — — 983 Total $ 82,699 $ 42,919 $ (1,957 ) $ 123,661 ___________ (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 $3.1 million as of December 31, 2015 and June 30, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

Regulatory Accounting_

Regulatory Accounting:	6 Months Ended
	Jun. 30, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Accounting	REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) June 30, 2016 December 31, 2015 June 30, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 20,603 $ 24,751 $ 26,862 Deferred gas cost adjustments (a)(d) 1 12,122 15,521 5,588 Gas price derivatives (a) 7 11,515 23,583 17,907 AFUDC (b) 45 13,879 12,870 12,321 Employee benefit plans (c) (e) 12 109,522 83,986 96,734 Environmental (a) subject to approval 1,144 1,180 1,224 Asset retirement obligations (a) 44 505 457 3,242 Bond issue cost (a) 22 3,061 3,133 3,204 Renewable energy standard adjustment (b) 5 2,679 5,068 5,629 Flow through accounting (c) 35 31,554 29,722 27,861 Decommissioning costs (f) 10 18,399 18,310 14,845 Gas supply contract termination 5 28,385 — — Other regulatory assets (a) 15 22,044 13,903 12,555 $ 275,412 $ 232,484 $ 227,972 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 32,868 $ 7,814 $ 16,114 Employee benefit plans (c) (e) 12 62,712 47,218 53,163 Cost of removal (a) 44 126,002 90,045 84,118 Other regulatory liabilities (c) 25 7,859 7,964 8,350 $ 229,441 $ 153,041 $ 161,745 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. (e) Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $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 varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We terminated the contract and settled the liability on April 29, 2016. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal. The increase from the prior periods is due to cost of removal recorded with the SourceGas purchase price allocation. See Note 2 for additional details.

Materials, Supplies and Fuel_

Materials, Supplies and Fuel:	6 Months Ended
	Jun. 30, 2016
Inventory, Net [Abstract]
Materials, Supplies and Fuel	MATERIALS, SUPPLIES AND FUEL The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Materials and supplies $ 67,440 $ 55,726 $ 54,646 Fuel - Electric Utilities 4,659 5,567 6,644 Natural gas in storage held for distribution 13,090 25,650 12,459 Total materials, supplies and fuel $ 85,189 $ 86,943 $ 73,749

Goodwill & Intangible Assets_

Goodwill & Intangible Assets:	6 Months Ended
	Jun. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	GOODWILL & INTANGIBLE ASSETS Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 250,487 $ 100,507 $ 8,765 359,759 Acquisition of SourceGas (a) — 943,694 — 943,694 Ending balance at June 30, 2016 $ 250,487 $ 1,044,201 $ 8,765 $ 1,303,453 __________ (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) 6,225 Amortization expense (441 ) Intangible assets, net, ending balance at June 30, 2016 $ 9,164 __________ (a) Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10 -year estimated useful lives. See Note 2 for more information.

Earnings Per Share_

Earnings Per Share:	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Net income (loss) available for common stock $ 669 $ (41,842 ) $ 40,671 $ (7,992 ) Weighted average shares - basic 51,514 44,617 51,279 44,579 Dilutive effect of: Equity Units (a) 1,362 — 1,068 — Equity compensation 110 — 107 — Weighted average shares - diluted (b) 52,986 44,617 52,454 44,579 __________ (a) Calculated using the treasury stock method. (b) Due to our net loss for the three and six months ended June 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 83,613 and 101,146 equity compensation shares were excluded from the computations for the three and six months ended June 30, 2015, respectively. The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Equity compensation 4 119 10 113 Anti-dilutive shares 4 119 10 113

Notes Payable_

Notes Payable:	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Short-term Debt [Text Block]	NOTES PAYABLE We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 75,000 $ 24,700 $ 76,800 $ 33,399 $ 105,760 $ 23,100 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 June 30, 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 until March 31, 2017, a period of four fiscal quarters following the SourceGas acquisition; it was previously 0.65 to 1.00 . The maximum Recourse Leverage Ratio returns to 0.65 to 1.00 on March 31, 2017. 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 June 30, 2016 Covenant Requirement Recourse Leverage Ratio 69% Less than 75% As of June 30, 2016 , we were in compliance with this covenant.

Long-Term Debt_

Long-Term Debt:	6 Months Ended
	Jun. 30, 2016
Long-term Debt, Unclassified [Abstract]
Long-term Debt [Text Block]	LONG-TERM DEBT AND CURRENT MATURITIES OF LONG-TERM DEBT Long-term debt was as follows (dollars in thousands): Interest Rate at June 30, 2016 June 30, 2016 December 31, 2015 June 30, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (867 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,754 ) (1,890 ) (2,027 ) 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 (243 ) — — Corporate term loan due June 30, 2017 (a) (b) 1.38% 340,000 — — Corporate term loan due April 12, 2017 (b) 1.40% 260,000 300,000 300,000 Corporate term loan due June 7, 2021 2.32% 27,278 — — Total Corporate Debt 2,198,414 1,322,110 1,022,973 Gas Utilities Senior secured notes due September 29, 2019 (a) (e) (f) 3.98% 99,272 — — Senior unsecured notes due April 1, 2017 (a) 5.90% 325,000 — — Unamortized discount on Senior unsecured notes due 2017 (77 ) — — 424,195 — — 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 ) (101 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (c) 0.43% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (c) 0.43% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (c) 0.75% 2,855 2,855 2,855 Total Electric Utilities Debt 544,758 544,756 544,754 Total long-term debt 3,167,367 1,866,866 1,567,727 Less current maturities 930,743 — — Less deferred financing costs (d) 15,277 13,184 11,357 Long-term debt, net of current maturities $ 2,221,347 $ 1,853,682 $ 1,556,370 _______________ (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 $1.5 million , $1.7 million and $1.9 million as of June 30, 2016 , December 31, 2015 and June 30, 2015 , respectively. (e) Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness. (f) Includes a $4.2 million fair value adjustment from the SourceGas purchase price allocation. Scheduled future maturities of debt, excluding amortization of premiums or discounts are (in thousands): Year Ended: 2016 $ 2,871 2017 $ 930,743 2018 $ 5,743 2019 $ 355,015 2020 $ 205,742 Thereafter $ 1,670,291 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at June 30, 2016 . Current Maturities of Long-Term Debt As of June 30, 2016, we have the following classified as Current maturities of long-term debt: Loan Interest Rate Current Maturities at June 30, 2016 Corporate Corporate term loan due April 12, 2017 1.40% $ 260,000 Corporate term loan due June 7, 2021 (a) 2.32% 5,743 Corporate term loan due June 30, 2017 1.38% 340,000 605,743 Gas Utilities Senior unsecured notes due April 1, 2017 5.90% 325,000 Current Maturities of Long-Term Debt $ 930,743 _______________ (a) Principal payments of $1.4 million are due quarterly . Debt Transactions In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in footnote 5, on June 7, 2016, we entered into a 2.32% , $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million , the first of which were paid on June 30, 2016. On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95% , 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 are amortized over the life of each respective note. Assumption of Long-Term Debt At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following: • $325 million , 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017. • $95 million , 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019. • $340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan is LIBOR plus a margin of 0.875% .

Equity_

Equity:	6 Months Ended
	Jun. 30, 2016
Statement of Stockholders' Equity [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	( 11 ) EQUITY A summary of the changes in equity is as follows: Six Months Ended June 30, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 — $ 1,465,867 Net income (loss) 40,671 2,632 43,303 Other comprehensive income (loss) (22,709 ) — (22,709 ) Dividends on common stock (43,270 ) — (43,270 ) Share-based compensation 2,192 — 2,192 Issuance of common stock 55,802 — 55,802 Dividend reinvestment and stock purchase plan 1,478 — 1,478 Other stock transactions (20 ) — (20 ) Sale of noncontrolling interest 62,416 114,886 177,302 Balance at June 30, 2016 $ 1,562,427 $ 117,518 $ 1,679,945 Six Months Ended June 30, 2015 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 — $ 1,353,884 Net income (loss) (7,992 ) — (7,992 ) Other comprehensive income (loss) (1,815 ) — (1,815 ) Dividends on common stock (36,292 ) — (36,292 ) Share-based compensation 1,601 — 1,601 Issuance of common stock — — — Dividend reinvestment and stock purchase plan 1,516 — 1,516 Other stock transactions (16 ) — (16 ) Balance at June 30, 2015 $ 1,310,886 $ — $ 1,310,886 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. During the three months ended June 30, 2016, we sold 809,649 common shares for $49 million , net of $0.5 million in commissions under the ATM equity offering program. Through June 30, 2016, we have sold and issued an aggregate of 930,649 shares of common stock under the ATM equity offering program for $56 million , net of $0.6 million in commissions. Additionally, 46,576 shares for net proceeds of $2.9 million have been sold, but were not settled and are not considered issued and outstanding as of June 30, 2016. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to AIA Energy North America LLC. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. ASC 810 requires a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, be recorded as an equity transaction, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of: June 30, 2016 December 31, 2015 June 30, 2015 (in thousands) Assets Current assets $ 12,681 $ — $ — Property, plant and equipment of variable interest entities, net $ 224,128 $ — $ — Liabilities Current liabilities $ 4,174 $ — $ —

Risk Management Activities_

Risk Management Activities:	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2015 Annual Report on Form 10-K. Market Risk Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to: • Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production; our retail natural gas marketing activities; and our fuel procurement for certain of our gas-fired generation assets; and • Interest rate risk associated with our variable-rate debt 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 swaps to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly. The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts and terms of the crude oil futures and natural gas futures and swaps held at our Oil and Gas segment are composed of short positions. We had the following short positions as of: June 30, 2016 December 31, 2015 June 30, 2015 Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 210,000 2,530,000 198,000 4,392,500 276,000 4,187,500 Maximum terms in months (b) 30 18 24 24 18 18 __________ (a) Crude oil in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged. Based on June 30, 2016 prices, a $2.7 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate. Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, fixed to float swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss), or the Condensed Consolidated Statements of Comprehensive Income (Loss). For hedging activities associated with our retail marketing operations, the effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income (Loss). The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We were in a net long position as of: June 30, 2016 December 31, 2015 June 30, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 18,080,000 54 20,580,000 60 17,270,000 66 Natural gas options purchased 3,770,000 20 2,620,000 3 3,980,000 9 Natural gas basis swaps purchased 15,320,000 54 18,150,000 60 14,445,000 54 Natural gas fixed for float swaps, net (b) 5,029,500 23 — 0 — 0 Natural gas physical commitments, net 1,666,800 9 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) 2,974,500 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased. 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: June 30, 2016 December 31, 2015 June 30, 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 0.83 0.83 0.50 1.33 1.00 1.50 Derivative assets, non-current $ — $ — $ — $ 3,441 $ — $ — Derivative liabilities, current $ 8,553 $ 18,500 $ 1,505 $ — $ 2,835 $ 3,289 Derivative liabilities, non-current $ — $ — $ — $ — $ 156 $ 1,433 __________ (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 June 30, 2016 market interest rates and balances related to our interest rate swaps, a loss of approximately $ 29 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 June 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (12,614 ) Interest expense $ 840 Interest expense $ — Commodity derivatives (2,847 ) Revenue (3,287 ) Revenue — Commodity derivatives 395 Fuel, purchased power and cost of natural gas sold 61 Fuel, purchased power and cost of natural gas sold — Total $ (15,066 ) $ (2,386 ) $ — Three Months Ended June 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (892 ) Interest expense $ (1,670 ) Interest expense $ — Commodity derivatives (2,245 ) Revenue 3,666 Revenue — Total $ (3,137 ) $ 1,996 $ — Six Months Ended June 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (30,665 ) Interest expense $ 1,690 Interest expense $ — Commodity derivatives (1,039 ) Revenue (6,939 ) Revenue — Commodity derivatives 773 Fuel, purchased power and cost of natural gas sold 151 Fuel, purchased power and cost of natural gas sold — Total $ (30,931 ) $ (5,098 ) $ — Six Months Ended June 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (1,778 ) Interest expense $ (3,107 ) Interest expense $ — Commodity derivatives 1,520 Revenue 7,598 Revenue — Total $ (258 ) $ 4,491 $ —

Fair Value Measurements_

Fair Value Measurements:	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Derivative Financial Instruments The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1 , 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 instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Corporate Activities: • The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting a Level 2 disclosure by using the credit default spread of the obligor, if available, or a generic credit default spread curve that takes into account our credit ratings, and the credit rating of our counterparty. Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of June 30, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Futures -- Oil — 1,950 — (816 ) 1,134 Options -- Gas — — — — — Basis Swaps -- Gas — 798 — (334 ) 464 Commodity derivatives — Utilities — 6,833 — (4,175 ) 2,658 Interest Rate Swaps — — — — — Total $ — $ 9,581 $ — $ (5,325 ) $ 4,256 Liabilities: Commodity derivatives — Oil and Gas Futures -- Oil — 157 — — 157 Options -- Gas — — — — — Basis Swaps -- Gas — 71 — — 71 Commodity derivatives — Utilities — 14,727 — (14,427 ) 300 Interest rate swaps — 28,558 — — 28,558 Total $ — $ 43,513 $ — $ (14,427 ) $ 29,086 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 Futures -- 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 Futures -- 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 June 30, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Futures -- Oil — 5,178 — (5,178 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,372 — (4,372 ) — Commodity derivatives — Utilities — 2,577 — (2,577 ) — Interest Rate Swaps — — — — — Total $ — $ 12,127 $ — $ (12,127 ) $ — Liabilities: Commodity derivatives — Oil and Gas Futures -- Oil — 112 — (112 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 498 — (498 ) — Commodity derivatives — Utilities — 18,758 — (18,758 ) — Interest rate swaps — 4,722 — — 4,722 Total $ — $ 24,090 $ — $ (19,368 ) $ 4,722 Fair Value Measures by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. Additionally, as of December 31, 2015 , and June 30, 2015 , the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 12 as they are netted in other current assets. The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of June 30, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2,549 $ — Commodity derivatives Derivative assets — non-current 81 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 44 Commodity derivatives Derivative liabilities — non-current — 226 Interest rate swaps Derivative liabilities — current — 28,558 Interest rate swaps Derivative liabilities — non-current — — Total derivatives designated as hedges $ 2,630 $ 28,828 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,481 $ — Commodity derivatives Derivative assets — non-current 145 — Commodity derivatives Derivative liabilities — current — 254 Commodity derivatives Derivative liabilities — non-current — 4 Total derivatives not designated as hedges $ 1,626 $ 258 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 June 30, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 6,931 $ — Commodity derivatives Derivative assets — non-current 2,619 — Commodity derivatives Derivative liabilities — current — 493 Commodity derivatives Derivative liabilities — non-current — 117 Interest rate swaps Derivative liabilities — current — 3,289 Interest rate swaps Derivative liabilities — non-current — 1,433 Total derivatives designated as hedges $ 9,550 $ 5,332 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 5,156 Commodity derivatives Derivative liabilities — non-current — 11,025 Total derivatives not designated as hedges $ — $ 16,181

Fair Value of Financial Instrum

Fair Value of Financial Instruments:	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 13 , were as follows (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 116,805 $ 116,805 $ 456,535 $ 456,535 $ 87,210 $ 87,210 Restricted cash and equivalents (a) $ 1,975 $ 1,975 $ 1,697 $ 1,697 $ 2,316 $ 2,316 Notes payable (a) $ 75,000 $ 75,000 $ 76,800 $ 76,800 $ 105,760 $ 105,760 Long-term debt, including current maturities, net of deferred financing costs (b) $ 3,152,090 $ 3,427,587 $ 1,853,682 $ 1,992,274 $ 1,556,370 $ 1,700,487 __________ (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):	6 Months Ended
	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss)	OTHER COMPREHENSIVE INCOME (LOSS) The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended Six Months Ended June 30, 2016 June 30, 2015 June 30, 2016 June 30, 2015 (Gains) losses on cash flow hedges: Interest rate swaps Interest expense $ 840 $ 1,670 $ 1,690 $ 3,107 Commodity contracts Revenue (3,287 ) (3,666 ) (6,939 ) (7,598 ) Commodity contracts Fuel, purchased power and cost of natural gas sold 61 — 151 — (2,386 ) (1,996 ) (5,098 ) (4,491 ) Income tax Income tax (benefit) expense 882 735 1,884 1,989 Reclassification adjustments related to cash flow hedges, net of tax $ (1,504 ) $ (1,261 ) $ (3,214 ) $ (2,502 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) $ (110 ) $ (110 ) Actuarial gain (loss) Operations and maintenance 494 705 988 1,410 439 650 878 1,300 Income tax Income tax (benefit) expense (154 ) (228 ) (307 ) (456 ) Reclassification adjustments related to defined benefit plans, net of tax $ 285 $ 422 $ 571 $ 844 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 ) Other comprehensive income (loss), net of tax 422 (3,227 ) (2,805 ) Balance as of June 30, 2015 $ 6,110 $ (22,969 ) $ (16,859 ) 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 ) Other comprehensive income (loss), net of tax (11,224 ) 285 (10,939 ) Balance as of June 30, 2016 $ (16,555 ) $ (15,209 ) $ (31,764 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information:	6 Months Ended
	Jun. 30, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six months ended June 30, 2016 June 30, 2015 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 52,917 $ 36,661 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (48,139 ) $ (37,698 ) Income taxes, net $ (1,162 ) $ (1,202 )

Employee Benefit Plans_

Employee Benefit Plans:	6 Months Ended
	Jun. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS On February 12, 2016, as disclosed in Note 2 , we completed the acquisition of SourceGas, adding an additional defined benefit pension plan, two additional non-pension defined benefit postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement, among other factors. In accordance with ASC 715, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a Regulatory asset and will be amortized over the average remaining service life of the plans. Amounts recognized in the Condensed Consolidated Balance 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, regulatory assets or regulatory liabilities. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. We accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. The discount rates used to measure the 2016 interest costs are 3.827% , 3.817% and 3.284% for pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively. The previous method would have used a discount rate for both service and interest costs of 4.575% for pension, 4.500% for supplemental non-qualified defined benefit and 4.165% for other postretirement benefit costs. The decrease in the total 2016 service and interest costs is approximately $2.8 million , $0.3 million and $0.4 million for the pension, supplemental non-qualified defined benefit and other postretirement benefit costs, respectively, as compared to the previous method. In connection with the acquisition related re-measurement of the SourceGas benefit plans we adopted the spot yield curve method, referenced above. The discount rates used to measure the 2016 interest costs are 3.690% for pension and 3.319% for other post retirement costs, effective February 11, 2016. The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 2,078 $ 1,494 $ 4,156 $ 2,988 Interest cost 3,936 3,880 7,872 7,760 Expected return on plan assets (5,766 ) (4,867 ) (11,531 ) (9,734 ) Prior service cost 15 15 30 30 Net loss (gain) 1,793 2,759 3,586 5,518 Net periodic benefit cost $ 2,056 $ 3,281 $ 4,113 $ 6,562 Defined Benefit Postretirement Healthcare Plans With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via Voluntary Employees’ Beneficiary Association, “VEBAs”. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 467 $ 464 $ 934 $ 928 Interest cost 485 450 970 900 Expected return on plan assets (70 ) (33 ) (140 ) (66 ) Prior service cost (benefit) (107 ) (107 ) (214 ) (214 ) Net loss (gain) 84 102 168 204 Net periodic benefit cost $ 859 $ 876 $ 1,718 $ 1,752 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 June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 878 $ 392 $ 907 $ 883 Interest cost 315 364 629 728 Prior service cost 1 1 1 2 Net loss (gain) 207 270 414 540 Net periodic benefit cost $ 1,401 $ 1,027 $ 1,951 $ 2,153 Contributions We anticipate that we will make contributions to the benefit plans in 2016 and 2017 . Contributions to the Defined Benefit Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ 10,200 $ 10,200 $ — $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 2,384 $ 2,384 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 784 $ 784 $ 1,627

Commitments and Contingencies_

Commitments and Contingencies:	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 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 $ 29,411 $ 44,789 $ 44,434 $ 40,636 $ 40,636 $ 192,651 $ 392,557 Facilities and equipment 1,247 2,216 2,207 1,676 1,359 3,326 12,031 Total $ 30,658 $ 47,005 $ 46,641 $ 42,312 $ 41,995 $ 195,977 $ 404,588 Also due to the acquisition, there are other commitments to purchase natural gas to meet customer needs, which are short-term or long-term in nature. At June 30, 2016, the long-term commitments to purchase physical quantities of natural gas under contracts indexed to the forward Northwest Wyoming Pool totaled 0.24 Bcf within one year, 1.20 Bcf within one to two years and 0.97 Bcf in the third year. Purchases under these contracts totaled $1.7 million for the six months ended June 30, 2016 which are recovered under the applicable states’ purchased-gas recovery mechanisms. Build Transfer Agreement On November 2, 2015, Colorado Electric executed a build-transfer agreement with Invenergy Wind Development Colorado, LLC to purchase the 60 MW, $109 million Peak View Wind Project. Peak View will be built by Invenergy Wind Development Colorado, LLC approximately 30 miles south of Pueblo, Colorado, in Huerfano and Las Animas counties. The estimated cost of $109 million includes taxes, transmission infrastructure and interconnection costs. Construction started in February of 2016 and is expected to be completed in late 2016. Under the build transfer agreement, Colorado Electric makes progress payments to Invenergy, which started in late 2015, and continue through completion of the project. Ownership of Peak View will transfer to Colorado Electric prior to commercial operation and will be operated as a utility-owned asset. BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric. At June 30, 2016 , the balance of BHC’s guarantee was approximately $47 million . The balance of the guarantee decreases as progress payments are made. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the second anniversary of the closing date. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of June 30, 2016 , we were in compliance with the debt covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at June 30, 2016 : • Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of June 30, 2016 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million .

Impairment of Assets_

Impairment of Assets:	6 Months Ended
	Jun. 30, 2016
Asset Impairment Charges [Abstract]
Asset Impairment Charges [Text Block]	IMPAIRMENT OF ASSETS Long-lived Assets Our Oil and Gas segment accounts for oil and gas activities under the full cost method of accounting. Under the full cost method, all productive and non-productive costs related to acquisition, exploration, development, abandonment and reclamation activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. In determining the ceiling value of our assets under the full cost accounting rules of the SEC, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. As a result of continued low commodity prices in 2016 and throughout 2015, we have recorded the following non-cash ceiling test impairments of our oil and gas assets included in our Oil and Gas segment for the three and six months ended June 30, 2016 and June 30, 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. During the second quarter of 2016, we recorded an $ 11 million pre-tax non-cash impairment of oil and gas assets. At June 30, 2016, for natural gas, the average NYMEX price was $2.24 per Mcf, adjusted to $1.01 per Mcf at the wellhead; for crude oil, the average NYMEX price was $43.12 per barrel, adjusted to $37.19 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. During the second quarter of 2015, we recorded a $94 million pre-tax non-cash impairment of oil and gas assets. At June 30, 2015, for natural gas, the average NYMEX price was $3.39 per Mcf, adjusted to $2.14 per Mcf at the wellhead; for crude oil, the average NYMEX price was $71.68 per barrel, adjusted to $63.76 per barrel at the wellhead. During the second quarter of 2016 we advanced our Oil and Gas strategy, identifying certain non-core assets which may be sold as they are not expected to be utilized in the Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million , in addition to the impairments noted above. Equity Investments in Unconsolidated Subsidiaries At June 30, 2015, our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. Due to sustained low commodity prices, recurring operating losses and future expectations, we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements. We valued this investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline is considered to be other than temporary. As a result we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million , the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system.

Income Taxes_

Income Taxes:	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended June 30, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) 16.9 2.6 Percentage depletion in excess of cost (5.9 ) 0.8 Accounting for uncertain tax positions adjustment 1.9 (0.5 ) Noncontrolling interest (b) (25.1 ) — Flow-through adjustments (10.6 ) 1.0 Inter-period adjustment 1.7 (6.5 ) AFUDC equity (5.8 ) 0.3 Other tax differences 0.5 — 8.6 % 32.7 % __________ (a) The increase in state income tax expense was due primarily to a change in projections, the impact of which was more pronounced in the current period due to significantly lower consolidated pre-tax net income. (b) The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016. The lower pre-tax income for the second quarter of 2016 is causing some of the percentages to not be reflective of the expected impact on full year operating results. Six Months Ended June 30, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 3.8 2.4 Percentage depletion in excess of cost (c) (13.5 ) 9.5 Inter-period adjustment (3.5 ) (22.6 ) Accounting for uncertain tax positions adjustment (d) (10.4 ) (11.9 ) Noncontrolling interest (1.9 ) — Transaction costs 2.3 — Flow-through adjustments (1.7 ) 9.5 Other tax differences (0.6 ) 2.7 9.5 % 24.6 % _________ (c) The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code. (d) The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. In the first quarter of 2016, we reached an agreement in principle with IRS Appeals in regards to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the 2008 IPP Transaction and the Aquila Transaction. An agreement in principle was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. We reversed approximately $35 million of the liability for unrecognized tax benefits, including interest, during the first quarter of 2016. The vast majority of such reversal was to restore accumulated deferred income taxes. We reversed accrued after-tax interest expense and tax credits of approximately $5.1 million associated with these liabilities in the first quarter of 2016. The cash taxes due as a result of the agreement in principle with IRS Appeals is estimated to be $8.0 million excluding interest.

Accrued Liabilities_

Accrued Liabilities:	6 Months Ended
	Jun. 30, 2016
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities Disclosure [Text Block]	ACCRUED LIABILITIES The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Accrued employee compensation, benefits and withholdings $ 45,991 $ 43,342 $ 35,126 Accrued property taxes 33,295 32,393 26,820 Accrued payments related to litigation expenses and settlements — 38,750 25,000 Customer deposits and prepayments 44,200 53,496 26,384 Accrued interest and contract adjustment payments 42,330 25,762 13,656 CIAC current portion (a) 20,211 14,745 — Other (none of which is individually significant) 32,223 23,573 33,542 Total accrued liabilities $ 218,250 $ 232,061 $ 160,528 _________ (a) Prior to December 31, 2015, CIACs were classified as non-current liabilities.

Management's Statement_ Managem

Management's Statement: Management's Statement (Policies)	6 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Segment Reporting	Segment Reporting We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to March 31, 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Coal Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments; however we will no longer separate the segments by business group. We are a customer-focused, growth-oriented, vertically-integrated utility company. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. 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.
Noncontrolling Interest	Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 11 for additional detail on Noncontrolling Interests.

Management's Statement_ Manag30

Management's Statement: Management's Statement (Tables)	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 2015 , respectively: For the Three Months Ended June 30, 2015 For the Six Months Ended June 30, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 67,264 $ (67,264 ) $ — $ 138,348 $ (138,348 ) $ — Non-regulated energy operations and maintenance $ 23,146 $ (23,146 ) $ — $ 45,196 $ (45,196 ) $ — Operations and maintenance $ — $ 90,410 $ 90,410 $ — $ 183,544 $ 183,544 Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 158,560 $ 2,921 $ 19,229 Gas 153,767 (1,806 ) 987 Power Generation (e) 1,546 20,168 5,683 Mining 3,922 7,125 724 Oil and Gas (a) 7,646 — (19,424 ) Corporate activities (c) — — (6,530 ) Inter-company eliminations — (28,408 ) — Total $ 325,441 $ — $ 669 Three Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 161,514 $ 2,509 17,632 Gas (d) 87,663 — 3,235 Power Generation 1,706 20,603 7,549 Mining 9,052 7,673 3,049 Oil and Gas (a) (b) 12,319 — (71,195 ) Corporate activities — — (2,112 ) Inter-company eliminations — (30,785 ) — Total $ 272,254 $ — $ (41,842 ) Six Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 322,091 $ 6,666 $ 38,444 Gas 422,434 — 32,914 Power Generation (e) 3,398 41,624 14,265 Mining 11,456 15,873 3,662 Oil and Gas (a) 16,021 — (26,448 ) Corporate activities (c) — — (22,166 ) Inter-company eliminations — (64,163 ) — Total $ 775,400 $ — $ 40,671 Six Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) 328,007 5,933 35,185 Gas (d) 341,795 — 26,823 Power Generation 3,659 41,324 15,694 Mining 17,194 15,465 6,059 Oil and Gas (a) (b) 23,586 — (90,310 ) Corporate activities — — (1,443 ) Inter-company eliminations — (62,722 ) — Total $ 714,241 $ — $ (7,992 ) ___________ (a) Net income (loss) available for common stock for the three and six months ended June 30, 2016 and June 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $16 million and $25 million and $63 million and $77 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) available for common stock for the three and six months ended June 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million . See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Net income (loss) available for common stock for the three and six months ended June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $4.1 million and $20 million , respectively, and after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million , respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $8.2 million and $25 million , respectively, and Net income of $0.1 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (e) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $2.6 million for the three and six months ended June 30, 2016.

Acquisition_ Acquisition (Table

Acquisition: Acquisition (Tables)	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Business Combination, Separately Recognized Transactions	(in thousands) Preliminary Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration Paid, net of working capital adjustment received $ 1,124,238 Preliminary Allocation of Purchase Price: Current Assets $ 111,629 Property, plant & equipment, net 1,047,584 Goodwill 943,694 Deferred charges and other assets, excluding goodwill 132,534 Current liabilities (167,613 ) Long-term debt (764,337 ) Deferred credits and other liabilities (179,253 ) Total preliminary consideration paid, net of working-capital adjustment received $ 1,124,238
Business Combination, Pro Forma Information	The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Revenue $ 325,441 $ 347,085 $ 854,362 $ 975,549 Net income (loss) available for common stock $ 4,658 $ (49,751 ) $ 72,978 $ 306 Earnings (loss) per share, Basic $ 0.09 $ (0.98 ) $ 1.42 $ 0.01 Earnings (loss) per share, Diluted $ 0.09 $ (0.98 ) $ 1.39 $ 0.01

Business Segment Information_ B

Business Segment Information: Business Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting Information, Additional Information [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 and six months ended June 30, 2015 , respectively: For the Three Months Ended June 30, 2015 For the Six Months Ended June 30, 2015 (in thousands) As Previously Reported Presentation Reclassification As Currently Reported As Previously Reported Presentation Reclassification As Currently Reported Utilities - operations and maintenance $ 67,264 $ (67,264 ) $ — $ 138,348 $ (138,348 ) $ — Non-regulated energy operations and maintenance $ 23,146 $ (23,146 ) $ — $ 45,196 $ (45,196 ) $ — Operations and maintenance $ — $ 90,410 $ 90,410 $ — $ 183,544 $ 183,544 Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 158,560 $ 2,921 $ 19,229 Gas 153,767 (1,806 ) 987 Power Generation (e) 1,546 20,168 5,683 Mining 3,922 7,125 724 Oil and Gas (a) 7,646 — (19,424 ) Corporate activities (c) — — (6,530 ) Inter-company eliminations — (28,408 ) — Total $ 325,441 $ — $ 669 Three Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) $ 161,514 $ 2,509 17,632 Gas (d) 87,663 — 3,235 Power Generation 1,706 20,603 7,549 Mining 9,052 7,673 3,049 Oil and Gas (a) (b) 12,319 — (71,195 ) Corporate activities — — (2,112 ) Inter-company eliminations — (30,785 ) — Total $ 272,254 $ — $ (41,842 ) Six Months Ended June 30, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 322,091 $ 6,666 $ 38,444 Gas 422,434 — 32,914 Power Generation (e) 3,398 41,624 14,265 Mining 11,456 15,873 3,662 Oil and Gas (a) 16,021 — (26,448 ) Corporate activities (c) — — (22,166 ) Inter-company eliminations — (64,163 ) — Total $ 775,400 $ — $ 40,671 Six Months Ended June 30, 2015 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric (d) 328,007 5,933 35,185 Gas (d) 341,795 — 26,823 Power Generation 3,659 41,324 15,694 Mining 17,194 15,465 6,059 Oil and Gas (a) (b) 23,586 — (90,310 ) Corporate activities — — (1,443 ) Inter-company eliminations — (62,722 ) — Total $ 714,241 $ — $ (7,992 ) ___________ (a) Net income (loss) available for common stock for the three and six months ended June 30, 2016 and June 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $16 million and $25 million and $63 million and $77 million , respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (b) Net income (loss) available for common stock for the three and six months ended June 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million . See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (c) Net income (loss) available for common stock for the three and six months ended June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $4.1 million and $20 million , respectively, and after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million , respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. (d) Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $8.2 million and $25 million , respectively, and Net income of $0.1 million and $1.4 million , respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment. (e) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $2.6 million for the three and six months ended June 30, 2016.
Reconciliation of Assets from Segment to Consolidated	Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: June 30, 2016 December 31, 2015 June 30, 2015 Segment: Electric (a) (b) $ 2,777,142 $ 2,720,004 $ 2,732,663 Gas (b) 3,142,293 999,778 920,624 Power Generation (a) 80,360 60,864 72,270 Mining 71,319 76,357 76,079 Oil and Gas (c) 171,228 208,956 275,068 Corporate activities (d) 152,522 576,358 132,210 Total assets $ 6,394,864 $ 4,642,317 $ 4,208,914 __________ (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 six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $119 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 June 30, 2015. (c) As a result of continued low commodity prices and the transition of Oil and Gas to support Cost of Service Gas programs, we recorded non-cash impairments of $40 million for the six months ended June 30, 2016 , $250 million for the year ended December 31, 2015, and $117 million for the six months ended June 30, 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)	6 Months Ended
	Jun. 30, 2016
Receivables [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts June 30, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 40,991 $ 34,174 $ (716 ) $ 74,449 Gas Utilities 47,600 23,124 (2,997 ) 67,727 Power Generation 1,229 — — 1,229 Mining 1,114 — — 1,114 Oil and Gas 3,094 — (13 ) 3,081 Corporate 2,627 — — 2,627 Total $ 96,655 $ 57,298 $ (3,726 ) $ 150,227 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 June 30, 2015 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities (a) $ 44,126 $ 32,660 $ (746 ) $ 76,040 Gas Utilities (a) 27,890 10,259 (1,198 ) 36,951 Power Generation 1,199 — — 1,199 Mining 3,402 — — 3,402 Oil and Gas 5,099 — (13 ) 5,086 Corporate 983 — — 983 Total $ 82,699 $ 42,919 $ (1,957 ) $ 123,661 ___________ (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 $3.1 million as of December 31, 2015 and June 30, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

Regulatory Accounting_ Regulato

Regulatory Accounting: Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) June 30, 2016 December 31, 2015 June 30, 2015 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 20,603 $ 24,751 $ 26,862 Deferred gas cost adjustments (a)(d) 1 12,122 15,521 5,588 Gas price derivatives (a) 7 11,515 23,583 17,907 AFUDC (b) 45 13,879 12,870 12,321 Employee benefit plans (c) (e) 12 109,522 83,986 96,734 Environmental (a) subject to approval 1,144 1,180 1,224 Asset retirement obligations (a) 44 505 457 3,242 Bond issue cost (a) 22 3,061 3,133 3,204 Renewable energy standard adjustment (b) 5 2,679 5,068 5,629 Flow through accounting (c) 35 31,554 29,722 27,861 Decommissioning costs (f) 10 18,399 18,310 14,845 Gas supply contract termination 5 28,385 — — Other regulatory assets (a) 15 22,044 13,903 12,555 $ 275,412 $ 232,484 $ 227,972 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 32,868 $ 7,814 $ 16,114 Employee benefit plans (c) (e) 12 62,712 47,218 53,163 Cost of removal (a) 44 126,002 90,045 84,118 Other regulatory liabilities (c) 25 7,859 7,964 8,350 $ 229,441 $ 153,041 $ 161,745 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. (d) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. (e) Increase compared to December 31, 2015 was driven by addition of the SourceGas employee benefit plans. (f) South Dakota Electric has approximately $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 varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a five year period. We terminated the contract and settled the liability on April 29, 2016. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal. The increase from the prior periods is due to cost of removal recorded with the SourceGas purchase price allocation. See Note 2 for additional details.

Materials, Supplies and Fuel_ M

Materials, Supplies and Fuel: Materials, Supplies and Fuel (Tables)	6 Months Ended
	Jun. 30, 2016
Inventory, Net [Abstract]
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Materials and supplies $ 67,440 $ 55,726 $ 54,646 Fuel - Electric Utilities 4,659 5,567 6,644 Natural gas in storage held for distribution 13,090 25,650 12,459 Total materials, supplies and fuel $ 85,189 $ 86,943 $ 73,749

Goodwill & Intangible Assets_ G

Goodwill & Intangible Assets: Goodwill & Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Following is a summary of Goodwill included in the accompanying Condensed Consolidated Balance Sheets (in thousands): Electric Utilities (b) Gas Utilities (b) Power Generation Total Ending balance at December 31, 2015 $ 250,487 $ 100,507 $ 8,765 359,759 Acquisition of SourceGas (a) — 943,694 — 943,694 Ending balance at June 30, 2016 $ 250,487 $ 1,044,201 $ 8,765 $ 1,303,453 __________ (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) 6,225 Amortization expense (441 ) Intangible assets, net, ending balance at June 30, 2016 $ 9,164 __________ (a) Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10 -year estimated useful lives. See Note 2 for more information.

Earnings Per Share_ Earnings Pe

Earnings Per Share: Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (Loss) was as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Net income (loss) available for common stock $ 669 $ (41,842 ) $ 40,671 $ (7,992 ) Weighted average shares - basic 51,514 44,617 51,279 44,579 Dilutive effect of: Equity Units (a) 1,362 — 1,068 — Equity compensation 110 — 107 — Weighted average shares - diluted (b) 52,986 44,617 52,454 44,579 __________ (a) Calculated using the treasury stock method. (b) Due to our net loss for the three and six months ended June 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 83,613 and 101,146 equity compensation shares were excluded from the computations for the three and six months ended June 30, 2015, respectively.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Equity compensation 4 119 10 113 Anti-dilutive shares 4 119 10 113

Notes Payable_ Notes Payable an

Notes Payable: Notes Payable and Long-term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of Short-term Debt	We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ 75,000 $ 24,700 $ 76,800 $ 33,399 $ 105,760 $ 23,100
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 June 30, 2016 Covenant Requirement Recourse Leverage Ratio 69% Less than 75%

Long-Term Debt_ Long-Term Debt

Long-Term Debt: Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt was as follows (dollars in thousands): Interest Rate at June 30, 2016 June 30, 2016 December 31, 2015 June 30, 2015 Corporate Remarketable junior subordinated notes due November 1, 2028 3.50% $ 299,000 $ 299,000 $ — Senior unsecured notes due January 15, 2026 3.95% 300,000 — — Unamortized discount on Senior unsecured notes due 2026 (867 ) — — Senior unsecured notes due November 30, 2023 4.25% 525,000 525,000 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,754 ) (1,890 ) (2,027 ) 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 (243 ) — — Corporate term loan due June 30, 2017 (a) (b) 1.38% 340,000 — — Corporate term loan due April 12, 2017 (b) 1.40% 260,000 300,000 300,000 Corporate term loan due June 7, 2021 2.32% 27,278 — — Total Corporate Debt 2,198,414 1,322,110 1,022,973 Gas Utilities Senior secured notes due September 29, 2019 (a) (e) (f) 3.98% 99,272 — — Senior unsecured notes due April 1, 2017 (a) 5.90% 325,000 — — Unamortized discount on Senior unsecured notes due 2017 (77 ) — — 424,195 — — 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 ) (101 ) First Mortgage Bonds due November 20, 2037 6.67% 110,000 110,000 110,000 Industrial development revenue bonds due September 1, 2021 (c) 0.43% 7,000 7,000 7,000 Industrial development revenue bonds due March 1, 2027 (c) 0.43% 10,000 10,000 10,000 Series 94A Debt, variable rate due June 1, 2024 (c) 0.75% 2,855 2,855 2,855 Total Electric Utilities Debt 544,758 544,756 544,754 Total long-term debt 3,167,367 1,866,866 1,567,727 Less current maturities 930,743 — — Less deferred financing costs (d) 15,277 13,184 11,357 Long-term debt, net of current maturities $ 2,221,347 $ 1,853,682 $ 1,556,370 _______________ (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 $1.5 million , $1.7 million and $1.9 million as of June 30, 2016 , December 31, 2015 and June 30, 2015 , respectively. (e) Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness. (f) Includes a $4.2 million fair value adjustment from the SourceGas purchase price allocation.
Schedule of Maturities of Long-term Debt	Scheduled future maturities of debt, excluding amortization of premiums or discounts are (in thousands): Year Ended: 2016 $ 2,871 2017 $ 930,743 2018 $ 5,743 2019 $ 355,015 2020 $ 205,742 Thereafter $ 1,670,291
Schedule Of Long-Term Debt Due In The Next Twelve Months	As of June 30, 2016, we have the following classified as Current maturities of long-term debt: Loan Interest Rate Current Maturities at June 30, 2016 Corporate Corporate term loan due April 12, 2017 1.40% $ 260,000 Corporate term loan due June 7, 2021 (a) 2.32% 5,743 Corporate term loan due June 30, 2017 1.38% 340,000 605,743 Gas Utilities Senior unsecured notes due April 1, 2017 5.90% 325,000 Current Maturities of Long-Term Debt $ 930,743 _______________ (a) Principal payments of $1.4 million are due quarterly .

Equity_ Equity (Tables)

Equity: Equity (Tables)	6 Months Ended
	Jun. 30, 2016
Statement of Stockholders' Equity [Abstract]
Schedule of Stockholders Equity	A summary of the changes in equity is as follows: Six Months Ended June 30, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 — $ 1,465,867 Net income (loss) 40,671 2,632 43,303 Other comprehensive income (loss) (22,709 ) — (22,709 ) Dividends on common stock (43,270 ) — (43,270 ) Share-based compensation 2,192 — 2,192 Issuance of common stock 55,802 — 55,802 Dividend reinvestment and stock purchase plan 1,478 — 1,478 Other stock transactions (20 ) — (20 ) Sale of noncontrolling interest 62,416 114,886 177,302 Balance at June 30, 2016 $ 1,562,427 $ 117,518 $ 1,679,945 Six Months Ended June 30, 2015 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2014 $ 1,353,884 — $ 1,353,884 Net income (loss) (7,992 ) — (7,992 ) Other comprehensive income (loss) (1,815 ) — (1,815 ) Dividends on common stock (36,292 ) — (36,292 ) Share-based compensation 1,601 — 1,601 Issuance of common stock — — — Dividend reinvestment and stock purchase plan 1,516 — 1,516 Other stock transactions (16 ) — (16 ) Balance at June 30, 2015 $ 1,310,886 $ — $ 1,310,886

Risk Management Activities_ Ris

Risk Management Activities: Risk Management Activities (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative [Line Items]
Schedule of Derivative Instruments	The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: June 30, 2016 December 31, 2015 June 30, 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 0.83 0.83 0.50 1.33 1.00 1.50 Derivative assets, non-current $ — $ — $ — $ 3,441 $ — $ — Derivative liabilities, current $ 8,553 $ 18,500 $ 1,505 $ — $ 2,835 $ 3,289 Derivative liabilities, non-current $ — $ — $ — $ — $ 156 $ 1,433 __________ (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 are composed of both long and short positions. We were in a net long position as of: June 30, 2016 December 31, 2015 June 30, 2015 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 18,080,000 54 20,580,000 60 17,270,000 66 Natural gas options purchased 3,770,000 20 2,620,000 3 3,980,000 9 Natural gas basis swaps purchased 15,320,000 54 18,150,000 60 14,445,000 54 Natural gas fixed for float swaps, net (b) 5,029,500 23 — 0 — 0 Natural gas physical commitments, net 1,666,800 9 — 0 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) 2,974,500 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.
Derivative Instruments, Gain (Loss)	The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands): Three Months Ended June 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (12,614 ) Interest expense $ 840 Interest expense $ — Commodity derivatives (2,847 ) Revenue (3,287 ) Revenue — Commodity derivatives 395 Fuel, purchased power and cost of natural gas sold 61 Fuel, purchased power and cost of natural gas sold — Total $ (15,066 ) $ (2,386 ) $ — Three Months Ended June 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (892 ) Interest expense $ (1,670 ) Interest expense $ — Commodity derivatives (2,245 ) Revenue 3,666 Revenue — Total $ (3,137 ) $ 1,996 $ — Six Months Ended June 30, 2016 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (30,665 ) Interest expense $ 1,690 Interest expense $ — Commodity derivatives (1,039 ) Revenue (6,939 ) Revenue — Commodity derivatives 773 Fuel, purchased power and cost of natural gas sold 151 Fuel, purchased power and cost of natural gas sold — Total $ (30,931 ) $ (5,098 ) $ — Six Months Ended June 30, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (1,778 ) Interest expense $ (3,107 ) Interest expense $ — Commodity derivatives 1,520 Revenue 7,598 Revenue — Total $ (258 ) $ 4,491 $ —
Oil and Gas [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	We had the following short positions as of: June 30, 2016 December 31, 2015 June 30, 2015 Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 210,000 2,530,000 198,000 4,392,500 276,000 4,187,500 Maximum terms in months (b) 30 18 24 24 18 18 __________ (a) Crude oil in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged.

Fair Value Measurements_ Fair V

Fair Value Measurements: Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy, Measured on Recurring Basis	The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of June 30, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Futures -- Oil — 1,950 — (816 ) 1,134 Options -- Gas — — — — — Basis Swaps -- Gas — 798 — (334 ) 464 Commodity derivatives — Utilities — 6,833 — (4,175 ) 2,658 Interest Rate Swaps — — — — — Total $ — $ 9,581 $ — $ (5,325 ) $ 4,256 Liabilities: Commodity derivatives — Oil and Gas Futures -- Oil — 157 — — 157 Options -- Gas — — — — — Basis Swaps -- Gas — 71 — — 71 Commodity derivatives — Utilities — 14,727 — (14,427 ) 300 Interest rate swaps — 28,558 — — 28,558 Total $ — $ 43,513 $ — $ (14,427 ) $ 29,086 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 Futures -- 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 Futures -- 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 June 30, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas Futures -- Oil — 5,178 — (5,178 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,372 — (4,372 ) — Commodity derivatives — Utilities — 2,577 — (2,577 ) — Interest Rate Swaps — — — — — Total $ — $ 12,127 $ — $ (12,127 ) $ — Liabilities: Commodity derivatives — Oil and Gas Futures -- Oil — 112 — (112 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 498 — (498 ) — Commodity derivatives — Utilities — 18,758 — (18,758 ) — Interest rate swaps — 4,722 — — 4,722 Total $ — $ 24,090 $ — $ (19,368 ) $ 4,722
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 June 30, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 2,549 $ — Commodity derivatives Derivative assets — non-current 81 — Interest rate swaps Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 44 Commodity derivatives Derivative liabilities — non-current — 226 Interest rate swaps Derivative liabilities — current — 28,558 Interest rate swaps Derivative liabilities — non-current — — Total derivatives designated as hedges $ 2,630 $ 28,828 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,481 $ — Commodity derivatives Derivative assets — non-current 145 — Commodity derivatives Derivative liabilities — current — 254 Commodity derivatives Derivative liabilities — non-current — 4 Total derivatives not designated as hedges $ 1,626 $ 258 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 June 30, 2015 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 6,931 $ — Commodity derivatives Derivative assets — non-current 2,619 — Commodity derivatives Derivative liabilities — current — 493 Commodity derivatives Derivative liabilities — non-current — 117 Interest rate swaps Derivative liabilities — current — 3,289 Interest rate swaps Derivative liabilities — non-current — 1,433 Total derivatives designated as hedges $ 9,550 $ 5,332 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ — $ — Commodity derivatives Derivative assets — non-current — — Commodity derivatives Derivative liabilities — current — 5,156 Commodity derivatives Derivative liabilities — non-current — 11,025 Total derivatives not designated as hedges $ — $ 16,181

Fair Value of Financial Instr43

Fair Value of Financial Instruments: Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 13 , were as follows (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 116,805 $ 116,805 $ 456,535 $ 456,535 $ 87,210 $ 87,210 Restricted cash and equivalents (a) $ 1,975 $ 1,975 $ 1,697 $ 1,697 $ 2,316 $ 2,316 Notes payable (a) $ 75,000 $ 75,000 $ 76,800 $ 76,800 $ 105,760 $ 105,760 Long-term debt, including current maturities, net of deferred financing costs (b) $ 3,152,090 $ 3,427,587 $ 1,853,682 $ 1,992,274 $ 1,556,370 $ 1,700,487 __________ (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 (L44

Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Tables)	6 Months Ended
	Jun. 30, 2016
Statement of Comprehensive Income [Abstract]
Reclassification Out of Accumulated Other Comprehensive Income (Loss)	The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands): Location on the Condensed Consolidated Statements of Income (Loss) Amount Reclassified from AOCI Three Months Ended Six Months Ended June 30, 2016 June 30, 2015 June 30, 2016 June 30, 2015 (Gains) losses on cash flow hedges: Interest rate swaps Interest expense $ 840 $ 1,670 $ 1,690 $ 3,107 Commodity contracts Revenue (3,287 ) (3,666 ) (6,939 ) (7,598 ) Commodity contracts Fuel, purchased power and cost of natural gas sold 61 — 151 — (2,386 ) (1,996 ) (5,098 ) (4,491 ) Income tax Income tax (benefit) expense 882 735 1,884 1,989 Reclassification adjustments related to cash flow hedges, net of tax $ (1,504 ) $ (1,261 ) $ (3,214 ) $ (2,502 ) Amortization of defined benefit plans: Prior service cost Operations and maintenance $ (55 ) $ (55 ) $ (110 ) $ (110 ) Actuarial gain (loss) Operations and maintenance 494 705 988 1,410 439 650 878 1,300 Income tax Income tax (benefit) expense (154 ) (228 ) (307 ) (456 ) Reclassification adjustments related to defined benefit plans, net of tax $ 285 $ 422 $ 571 $ 844
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 ) Other comprehensive income (loss), net of tax 422 (3,227 ) (2,805 ) Balance as of June 30, 2015 $ 6,110 $ (22,969 ) $ (16,859 ) 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 ) Other comprehensive income (loss), net of tax (11,224 ) 285 (10,939 ) Balance as of June 30, 2016 $ (16,555 ) $ (15,209 ) $ (31,764 )

Supplemental Disclosure of Ca45

Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2016
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Six months ended June 30, 2016 June 30, 2015 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 52,917 $ 36,661 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (48,139 ) $ (37,698 ) Income taxes, net $ (1,162 ) $ (1,202 )

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures	Amounts recognized in the Condensed Consolidated Balance 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 June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 2,078 $ 1,494 $ 4,156 $ 2,988 Interest cost 3,936 3,880 7,872 7,760 Expected return on plan assets (5,766 ) (4,867 ) (11,531 ) (9,734 ) Prior service cost 15 15 30 30 Net loss (gain) 1,793 2,759 3,586 5,518 Net periodic benefit cost $ 2,056 $ 3,281 $ 4,113 $ 6,562 Defined Benefit Postretirement Healthcare Plans With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via Voluntary Employees’ Beneficiary Association, “VEBAs”. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan. The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 467 $ 464 $ 934 $ 928 Interest cost 485 450 970 900 Expected return on plan assets (70 ) (33 ) (140 ) (66 ) Prior service cost (benefit) (107 ) (107 ) (214 ) (214 ) Net loss (gain) 84 102 168 204 Net periodic benefit cost $ 859 $ 876 $ 1,718 $ 1,752 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 June 30, Six Months Ended June 30, 2016 2015 2016 2015 Service cost $ 878 $ 392 $ 907 $ 883 Interest cost 315 364 629 728 Prior service cost 1 1 1 2 Net loss (gain) 207 270 414 540 Net periodic benefit cost $ 1,401 $ 1,027 $ 1,951 $ 2,153
Schedule of Defined Benefit Plans Contributions	Contributions and anticipated contributions are as follows (in thousands): Contributions Made Contributions Made Additional Contributions Contributions Three Months Ended June 30, 2016 Six Months Ended June 30, 2016 Anticipated for 2016 Anticipated for 2017 Defined Benefit Pension Plans $ 10,200 $ 10,200 $ — $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,192 $ 2,384 $ 2,384 $ 4,744 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 392 $ 784 $ 784 $ 1,627

Commitments and Contingencies_

Commitments and Contingencies: Supply Commitment (Tables)	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment	we assumed various commitments relating to natural gas supply and transportation commitments and lease commitments, as summarized below (in thousands): 2016 2017 2018 2019 2020 Thereafter Total Future minimum payments Pipeline capacity obligations $ 29,411 $ 44,789 $ 44,434 $ 40,636 $ 40,636 $ 192,651 $ 392,557 Facilities and equipment 1,247 2,216 2,207 1,676 1,359 3,326 12,031 Total $ 30,658 $ 47,005 $ 46,641 $ 42,312 $ 41,995 $ 195,977 $ 404,588

Income Taxes_ Income Taxes (Tab

Income Taxes: Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended June 30, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) 16.9 2.6 Percentage depletion in excess of cost (5.9 ) 0.8 Accounting for uncertain tax positions adjustment 1.9 (0.5 ) Noncontrolling interest (b) (25.1 ) — Flow-through adjustments (10.6 ) 1.0 Inter-period adjustment 1.7 (6.5 ) AFUDC equity (5.8 ) 0.3 Other tax differences 0.5 — 8.6 % 32.7 % __________ (a) The increase in state income tax expense was due primarily to a change in projections, the impact of which was more pronounced in the current period due to significantly lower consolidated pre-tax net income. (b) The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016. The lower pre-tax income for the second quarter of 2016 is causing some of the percentages to not be reflective of the expected impact on full year operating results. Six Months Ended June 30, Tax (benefit) expense 2016 2015 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) 3.8 2.4 Percentage depletion in excess of cost (c) (13.5 ) 9.5 Inter-period adjustment (3.5 ) (22.6 ) Accounting for uncertain tax positions adjustment (d) (10.4 ) (11.9 ) Noncontrolling interest (1.9 ) — Transaction costs 2.3 — Flow-through adjustments (1.7 ) 9.5 Other tax differences (0.6 ) 2.7 9.5 % 24.6 %

Accrued Liabilities_ Accrued Li

Accrued Liabilities: Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: June 30, 2016 December 31, 2015 June 30, 2015 Accrued employee compensation, benefits and withholdings $ 45,991 $ 43,342 $ 35,126 Accrued property taxes 33,295 32,393 26,820 Accrued payments related to litigation expenses and settlements — 38,750 25,000 Customer deposits and prepayments 44,200 53,496 26,384 Accrued interest and contract adjustment payments 42,330 25,762 13,656 CIAC current portion (a) 20,211 14,745 — Other (none of which is individually significant) 32,223 23,573 33,542 Total accrued liabilities $ 218,250 $ 232,061 $ 160,528 _________ (a) Prior to December 31, 2015, CIACs were classified as non-current liabilities.

Management's Statement_ Segment

Management's Statement: Segment Reporting (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Prior Period Reclassification Adjustment		$ 90,410		$ 183,544
Utilities - Operating and maintenance		0		0
Operating Costs, Nonregulated Energy Operations		0		0
Operations and maintenance	$ 112,541	90,410	$ 219,603	183,544
Scenario, Previously Reported [Member]
Prior Period Reclassification Adjustment		0		0
Utilities Group [Member]
Prior Period Reclassification Adjustment		(67,264)		(138,348)
Utilities Group [Member] | Scenario, Previously Reported [Member]
Prior Period Reclassification Adjustment		67,264		138,348
Non Regulated Energy Group [Member]
Prior Period Reclassification Adjustment		(23,146)		(45,196)
Non Regulated Energy Group [Member] | Scenario, Previously Reported [Member]
Prior Period Reclassification Adjustment		$ 23,146		$ 45,196

Management's Statement_ Simplif

Management's Statement: Simplifying The Presentation Of Debt Issuance Costs (Details) - USD ($) $ in Millions	Dec. 31, 2015	Jun. 30, 2015
Deferred Finance Costs [Member]
Prior Period Reclassification Adjustment	$ 13	$ 11

Acquisition_ Acquisition (Detai

Acquisition: Acquisition (Details) $ / shares in Units, $ in Thousands	Apr. 29, 2016USD ($)	Feb. 12, 2016USD ($)customerutilitymi	Jan. 13, 2016USD ($)	Nov. 23, 2015USD ($)shares	Jun. 30, 2016USD ($)$ / shares		Jun. 30, 2015USD ($)$ / shares	Jun. 30, 2016USD ($)$ / shares		Jun. 30, 2015USD ($)$ / shares	Apr. 30, 2016$ / Btu	Dec. 31, 2015USD ($)
Acquisition Narrative [Abstract]
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired, Before Working Capital Adjustment								$ 1,135,000
Proceeds From Issuance Of Common Stock and Sale Of Interest In Corporate Units				$ 536,000
Long-term debt - issuances			$ 546,000					574,672		$ 300,000
Revenue					$ 325,441		$ 272,254	775,400		714,241
Net income (loss) available for common stock					669		(41,842)	40,671		(7,992)
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital Adjustment To Goodwill		$ 2,700
Acquisition Recap [Abstract]
Goodwill		$ 943,694			$ 1,303,453		353,396	$ 1,303,453		353,396		$ 359,759
Settlement of Gas Supply Contract [Abstract]
Early Termination Settlement of Gas Supply Contract	$ 40,000
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma - Combined Federal and State income Tax Rate								37.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners					0.50%			0.50%
Minimum [Member]
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu											6
Maximum [Member]
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu											8
Corporate[Member]
Acquisition Narrative [Abstract]
Business Acquisition, Transaction Costs					$ 6,300			$ 31,000		700
Revenue					0		0	0		0
Net income (loss) available for common stock					(6,530)	[1]	(2,112)	(22,166)	[1]	(1,443)
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					70,000			145,000
Net income (loss) available for common stock					(3,000)			4,600
Goodwill, Expected Tax Deductible Amount					214,000			214,000
Acquisition Recap [Abstract]
Preliminary Purchase Price		$ 1,894,882
Less: Long-term debt assumed		(760,000)
Less: Working capital adjustment received		(10,644)
Consideration Paid, net of working capital adjustment received		1,124,238
Current Assets		111,629
Property, plant & equipment, net		1,047,584
Deferred charges and other assets, excluding goodwill		132,534
Current liabilities		(167,613)
Long-term debt		(764,337)
Deferred credits and other liabilities		$ (179,253)
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma - Revenue					325,441		347,085	854,362		975,549
Pro Forma - Net income (loss) available for common stock					$ 4,658		$ (49,751)	$ 72,978		$ 306
Pro Forma - Earnings per share, Basic (usd per share) | $ / shares					$ 0.09		$ (0.98)	$ 1.42		$ 0.01
Pro Forma - Earnings per share, Diluted (usd per share) | $ / shares					$ 0.09		$ (0.98)	$ 1.39		$ 0.01
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]	Net income (loss) available for common stock for the three and six months ended June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $4.1 million and $20 million, respectively, and after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million, respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Business Segment Information_ I

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Segment Reporting Information
Revenue		$ 325,441		$ 272,254		$ 775,400		$ 714,241
Net income (loss) available for common stock		669		(41,842)		40,671		(7,992)
Equity Method Investment, Other than Temporary Impairment, Net of Income Taxes				3,400
Prior Period Reclassification Adjustment				90,410				183,544
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest		2,614		0		2,662		0
Revenue [Member]
Segment Reporting Information
Prior Period Reclassification Adjustment				8,200				25,000
Net Income (Loss) Available to Common Stockholders, Basic [Member]
Segment Reporting Information
Prior Period Reclassification Adjustment				100				1,400
Inter-company eliminations [Member]
Segment Reporting Information
Revenue		(28,408)		(30,785)		(64,163)		(62,722)
Net income (loss) available for common stock		0		0		0		0
Corporate activities[Member]
Segment Reporting Information
Revenue		0		0		0		0
Net income (loss) available for common stock		(6,530)	[1]	(2,112)		(22,166)	[1]	(1,443)
Business Acquisition, Transaction Costs		6,300				31,000		700
Corporate activities[Member] | Incremental, Non-Recurring Acquisition Costs (Net of Tax) [Member]
Segment Reporting Information
Business Acquisition, Transaction Costs		4,100				20,000
Corporate activities[Member] | Labor (Net Of Tax) [Member]
Segment Reporting Information
Business Acquisition, Transaction Costs		2,000				5,700
Consolidation, Eliminations [Member]
Segment Reporting Information
Revenue		0		0		0		0
Electric Utilities [Member]
Segment Reporting Information
Revenue		158,560		161,514	[2]	322,091		328,007	[2]
Net income (loss) available for common stock		19,229		17,632	[2]	38,444		35,185	[2]
Electric Utilities [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		2,921		2,509	[2]	6,666		5,933	[2]
Gas Utilities [Member]
Segment Reporting Information
Revenue		153,767		87,663	[2]	422,434		341,795	[2]
Net income (loss) available for common stock		987		3,235	[2]	32,914		26,823	[2]
Gas Utilities [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		(1,806)		0	[2]	0		0	[2]
Power Generation [Member]
Segment Reporting Information
Revenue		1,546		1,706		3,398		3,659
Net income (loss) available for common stock		5,683	[3]	7,549		14,265	[3]	15,694
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest		2,600
Power Generation [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		20,168		20,603		41,624		41,324
Mining [Member]
Segment Reporting Information
Revenue		3,922		9,052		11,456		17,194
Net income (loss) available for common stock		724		3,049		3,662		6,059
Mining [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		7,125		7,673		15,873		15,465
Oil and Gas [Member]
Segment Reporting Information
Revenue		7,646		12,319		16,021		23,586
Net income (loss) available for common stock	[4]	(19,424)		(71,195)	[5]	(26,448)		(90,310)	[5]
Impairment of Oil and Gas Properties Net of Tax		16,000		63,000		25,000		77,000
Oil and Gas [Member] | Inter-company eliminations [Member]
Segment Reporting Information
Revenue		$ 0		$ 0		$ 0		$ 0
[1]	Net income (loss) available for common stock for the three and six months ended June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $4.1 million and $20 million, respectively, and after-tax internal labor costs attributable to the acquisition of $2.0 million and $5.7 million, respectively. See Note 2 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
[2]	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utility segment. Cheyenne Light’s gas utility results for the three and six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Revenue of $8.2 million and $25 million, respectively, and Net income of $0.1 million and $1.4 million, respectively, previously reported in the Electric Utility segment in 2015 are now included in the Gas Utility segment.
[3]	Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $2.6 million for the three and six months ended June 30, 2016.
[4]	Net income (loss) available for common stock for the three and six months ended June 30, 2016 and June 30, 2015 includes non-cash after-tax impairments of oil and gas properties of $16 million and $25 million and $63 million and $77 million, respectively. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
[5]	Net income (loss) available for common stock for the three and six months ended June 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million. 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			6 Months Ended			12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015		Dec. 31, 2015
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		$ 6,394,864	$ 4,208,914		$ 6,394,864	$ 4,208,914		$ 4,642,317
Impairment of long-lived assets		25,497	94,484		39,993	116,520
Corporate activities[Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		152,522	132,210		152,522	132,210		576,358	[1]
Electric Utilities [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	[2]	2,777,142	2,732,663	[3]	2,777,142	2,732,663	[3]	2,720,004	[3]
Gas Utilities [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		3,142,293	920,624	[3]	3,142,293	920,624	[3]	999,778	[3]
Power Generation [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	[2]	80,360	72,270		80,360	72,270		60,864
Mining [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets		71,319	76,079		71,319	76,079		76,357
Oil and Gas [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	[4]	$ 171,228	275,068		171,228	275,068		208,956
Impairment of long-lived assets					$ 40,000			250,000
Assets, Total [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Prior Period Reclassification Adjustment Balance Sheet			$ 119,000			$ 119,000		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 six months ended June 30, 2015 have been reclassified from the Electric Utility segment to the Gas Utility segment. Assets of $135 million and $119 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 June 30, 2015.
[4]	As a result of continued low commodity prices and the transition of Oil and Gas to support Cost of Service Gas programs, we recorded non-cash impairments of $40 million for the six months ended June 30, 2016, $250 million for the year ended December 31, 2015, and $117 million for the six months ended June 30, 2015. See Note 19 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable_ Accounts55

Accounts Receivable: Accounts Receivable (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015		Jun. 30, 2015
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (3,726)	$ (1,741)		$ (1,957)
Accounts receivable, net	150,227	147,486		123,661
Corporate[Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	2,627	1,025		983
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(716)	(727)	[1]	(746)	[1]
Accounts receivable, net	74,449	76,826	[1]	76,040	[1]
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(2,997)	(1,001)	[1]	(1,198)	[1]
Accounts receivable, net	67,727	62,199	[1]	36,951	[1]
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	1,229	1,187		1,199
Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0		0
Accounts receivable, net	1,114	2,760		3,402
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(13)		(13)
Accounts receivable, net	3,081	3,489		5,086
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	96,655	80,484		82,699
Billed Revenues [Member] | Corporate[Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,627	1,025		983
Billed Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	40,991	41,679	[1]	44,126	[1]
Billed Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	47,600	30,331	[1]	27,890	[1]
Billed Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,229	1,187		1,199
Billed Revenues [Member] | Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,114	2,760		3,402
Billed Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,094	3,502		5,099
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	57,298	68,743		42,919
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	34,174	35,874	[1]	32,660	[1]
Unbilled Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	23,124	32,869	[1]	10,259	[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		$ 3,100
[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 $3.1 million as of December 31, 2015 and June 30, 2015, respectively, previously reported in the Electric Utility segment is now presented in the Gas Utility segment.

Regulatory Accounting_ Regula56

Regulatory Accounting: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 275,412	$ 232,484	$ 227,972
Regulatory Liabilities		$ 229,441	153,041	161,745
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Liabilities	[1],[2]	$ 32,868	7,814	16,114
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Liabilities	[3],[4]	$ 62,712	47,218	53,163
Cost of removal
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Liabilities	[2]	$ 126,002	90,045	84,118
Other regulatory liabilities
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		25 years
Regulatory Liabilities	[3]	$ 7,859	7,964	8,350
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets	[1],[2]	$ 20,603	24,751	26,862
Deferred gas cost adjustments
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets	[1],[2]	$ 12,122	15,521	5,588
Gas price derivatives
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		7 years
Regulatory Assets	[2]	$ 11,515	23,583	17,907
AFUDC
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		45 years
Regulatory Assets	[5]	$ 13,879	12,870	12,321
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Assets	[3],[4]	$ 109,522	83,986	96,734
Environmental
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	[2]	$ 1,144	1,180	1,224
Asset retirement obligations
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Assets	[2]	$ 505	457	3,242
Bond issue cost
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		22 years
Regulatory Assets	[2]	$ 3,061	3,133	3,204
Renewable energy standard adjustment
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets	[5]	$ 2,679	5,068	5,629
Flow through accounting
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		35 years
Regulatory Assets	[3]	$ 31,554	29,722	27,861
Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		10 years
Regulatory Assets	[6]	$ 18,399	18,310	14,845
Gas supply contract termination
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets		$ 28,385	0	0
Other regulatory assets
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		15 years
Regulatory Assets	[2]	$ 22,044	$ 13,903	$ 12,555
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.
[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)	Apr. 30, 2016$ / Btu
Minimum [Member]
Oil and Gas Delivery Commitments and Contracts, Fixed Price	6
Maximum [Member]
Oil and Gas Delivery Commitments and Contracts, Fixed Price	8

Materials, Supplies and Fuel_58

Materials, Supplies and Fuel: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Inventory, Net [Abstract]
Materials and supplies	$ 67,440	$ 55,726	$ 54,646
Fuel - Electric Utilities	4,659	5,567	6,644
Natural gas in storage held for distribution	13,090	25,650	12,459
Total materials, supplies and fuel	$ 85,189	$ 86,943	$ 73,749

Goodwill & Intangible Assets_59

Goodwill & Intangible Assets: Goodwill (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Goodwill, beginning balance		$ 359,759
Additions	[1]	943,694
Goodwill, ending balance		1,303,453
Electric Utilities [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	[2]	250,487
Additions		0
Goodwill, ending balance	[2]	250,487
Gas Utilities [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	[2]	100,507
Goodwill, ending balance	[2]	1,044,201
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	[1]	$ 943,694
Goodwill [Member]
Goodwill [Line Items]
Prior Period Reclassification Adjustment Balance Sheet			$ 6,300
[1]	Represents preliminary goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.
[2]	Goodwill of $6.3 million is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utility segment, previously reported in the Electric Utilities segment. See Note 1 for additional details.

Goodwill & Intangible Assets_ I

Goodwill & Intangible Assets: Intangible Assets (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)
Finite-lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 3,380
Amortization expense	(441)
Intangible assets, net, ending balance	$ 9,164
Source Gas [Member]
Finite-Lived Intangible Assets [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	10 years
Finite-lived Intangible Assets [Roll Forward]
Additions, net	$ 6,225	[1]
[1]	Intangible assets, net acquired from SourceGas are primarily non-regulated customer relationships, and are amortized over their 10-year estimated useful lives. See Note 2 for more information.

Earnings Per Share_ Earnings 61

Earnings Per Share: Earnings Per Share (Details) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015		Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Net income (loss) available for common stock		$ 669	$ (41,842)		$ 40,671	$ (7,992)
Weighted average shares - basic		51,514,000	44,617,000		51,279,000	44,579,000
Dilutive effect of:
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	[1]	1,362,000	0		1,068,000	0
Equity compensation		110,000	0		107,000	0
Weighted average shares - diluted		52,986,000	44,617,000	[2]	52,454,000	44,579,000	[2]
Securities Excluded From Diluted Earnings Per Share Due To Net Loss			83,613			101,146
[1]	Calculated using the treasury stock method.
[2]	Due to our net loss for the three and six months ended June 30, 2015, potentially dilutive securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing dilutive net loss per share, 83,613 and 101,146 equity compensation shares were excluded from the computations for the three and six months ended June 30, 2015, respectively.

Earnings Per Share_ Anti-diluti

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	4	119	10	113
Stock Compensation Plan [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	4	119	10	113

Notes Payable_ Notes Payable (D

Notes Payable: Notes Payable (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Revolving Credit Facility [Line Items]
Balance Outstanding	$ 75,000	$ 76,800	$ 105,760
Revolving Credit Facility [Member]
Revolving Credit Facility [Line Items]
Balance Outstanding	75,000	76,800	105,760
Letters of Credit	24,700	$ 33,399	$ 23,100
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	Jun. 30, 2016USD ($)	Feb. 12, 2016	Feb. 11, 2016	Jan. 13, 2016USD ($)	Dec. 31, 2015USD ($)	Jun. 30, 2015USD ($)
Long-term Debt, Gross	$ 3,167,367				$ 1,866,866	$ 1,567,727
Revolving Credit Facility [Member]
Recourse Leverage Ratio	69.00%
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 Deb65

Long-Term Debt: Long-Term Debt (Details) - USD ($) $ in Thousands		Jun. 30, 2016		Jun. 07, 2016	Feb. 12, 2016	Jan. 13, 2016	Dec. 31, 2015	Jun. 30, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 3,167,367					$ 1,866,866	$ 1,567,727
Long-term Debt, Current Maturities		(930,743)					0	0
Deferred Finance Costs, Net	[1]	(15,277)					(13,184)	(11,357)
Long-term Debt, Excluding Current Maturities		2,221,347					1,853,682	1,556,370
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Net		(1,500)					(1,700)	(1,900)
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		$ 424,195					0	0
Gas Utilities [Member] | Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[2],[3],[4]	3.98%
Long-term Debt, Gross		$ 99,272	[2],[3],[4]				0	0
Gas Utilities [Member] | Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[4]	5.90%
Long-term Debt, Gross		$ 325,000	[4]				0	0
Debt Instrument, Unamortized Discount		(77)					0	0
Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 544,758					544,756	544,754
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)	(101)
Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.67%
Long-term Debt, Gross		$ 110,000					110,000	110,000
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[5]	0.43%
Long-term Debt, Gross	[5]	$ 7,000					7,000	7,000
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[5]	0.43%
Long-term Debt, Gross	[5]	$ 10,000					10,000	10,000
Electric Utilities [Member] | Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[5]	0.75%
Long-term Debt, Gross	[5]	$ 2,855					2,855	2,855
Corporate[Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,198,414					1,322,110	1,022,973
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		$ (867)					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		$ (1,754)					(1,890)	(2,027)
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		$ (243)					0	0
Corporate[Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.32%
Long-term Debt, Gross		$ 27,278					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, Percentage Bearing Variable Interest, Percentage Rate	[4],[6]	1.38%
Long-term Debt, Gross		$ 340,000	[4],[6]				0	0
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due April 2017 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[6]	1.40%
Long-term Debt, Gross	[6]	$ 260,000					$ 300,000	$ 300,000
Corporate[Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate				2.32%
Long-term Debt, Gross				$ 29,000
Source Gas [Member]
Debt Instrument [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt, Working Capital Adjustment					$ 4,200
Source Gas [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, Percentage Bearing Variable Interest, Percentage Rate	[4],[6]				0.875%
Source Gas [Member] | Gas Utilities [Member] | Senior Secured Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[2],[4]				3.98%
Source Gas [Member] | Gas Utilities [Member] | Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	[4]				5.90%
[1]	Includes deferred financing costs associated with our Revolving Credit Facility of $1.5 million, $1.7 million and $1.9 million as of June 30, 2016, December 31, 2015 and June 30, 2015, respectively.
[2]	Currently unsecured, required to be ratably secured if Black Hills Gas Holdings incurs other secured indebtedness.
[3]	Includes a $4.2 million fair value adjustment from the SourceGas purchase price allocation.
[4]	Long-term debt assumed with the SourceGas Acquisition.
[5]	Variable interest rate.
[6]	Variable interest rate, based on LIBOR plus a spread.

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) $ in Thousands	Jun. 30, 2016USD ($)
Long-term Debt, Unclassified [Abstract]
2,016	$ 2,871
2,017	930,743
2,018	5,743
2,019	355,015
2,020	205,742
Thereafter	$ 1,670,291

Long-Term Debt_ Current Maturit

Long-Term Debt: Current Maturities of Long-Term Debt (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Jun. 07, 2016
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months		$ 930,743
Corporate activities[Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months		605,743
Black Hills Corporation [Member] | Corporate activities[Member] | Corporate Term Loan Due April 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months		$ 260,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[1]	1.40%
Black Hills Corporation [Member] | Corporate activities[Member] | Corporate Term Loan Due June 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.32%
Black Hills Corporation [Member] | Corporate activities[Member] | Corporate Term Loan Due June 2021 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months	[2]	$ 5,743
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate			2.32%
Debt Instrument, Periodic Payment, Principal		$ 1,400
Debt Instrument, Frequency of Periodic Payment		quarterly
Black Hills Corporation [Member] | Corporate activities[Member] | Corporate Term Loan Due June 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months		$ 340,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[1],[3]	1.38%
Gas Utilities [Member] | Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months		$ 325,000
Debt Instrument, Interest Rate, Stated Percentage	[3]	5.90%
[1]	Variable interest rate, based on LIBOR plus a spread.
[2]	Principal payments of $1.4 million are due quarterly.
[3]	Long-term debt assumed with the SourceGas Acquisition.

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands	Jun. 06, 2016	Jan. 13, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 07, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 3,167,367	$ 1,567,727		$ 1,866,866
Long-term debt - issuances		$ 546,000	574,672	300,000
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
Corporate activities[Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			2,198,414	1,022,973		1,322,110
Corporate activities[Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 27,278	0		0
Debt Instrument, Interest Rate, Stated Percentage			2.32%
Corporate activities[Member] | Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 300,000	0		0
Debt Instrument, Interest Rate, Stated Percentage			3.95%
Corporate activities[Member] | Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 250,000	$ 0		$ 0
Debt Instrument, Interest Rate, Stated Percentage			2.50%
London Interbank Offered Rate (LIBOR) [Member] | Corporate activities[Member] | Corporate Term Loan Due June 2021 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate					2.32%
Long-term Debt, Gross					$ 29,000
Debt Instrument, Frequency of Periodic Payment			quarterly
Debt Instrument, Periodic Payment	$ 1,600

Long-Term Debt_ Assumption of B

Long-Term Debt: Assumption of Black Hills Holdings LTD (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Feb. 12, 2016
Source Gas [Member]
Debt Instrument [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt			$ 760,000
Senior Unsecured Notes Due 2017 [Member] | Gas Utilities [Member]
Debt Instrument [Line Items]
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]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	[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]
Debt Instrument, Interest Rate, Stated Percentage	[1],[2],[3]	3.98%
Senior Secured Notes due 2019 [Member] | Gas Utilities [Member] | Source Gas [Member]
Debt Instrument [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	[1],[2]		$ 95,000
Debt Instrument, Interest Rate, Stated Percentage	[1],[2]		3.98%
Black Hills Corporation [Member] | London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan Due June 2017 [Member] | Source Gas [Member]
Debt Instrument [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	[1],[4]		$ 340,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	[1],[4]		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]	Includes a $4.2 million fair value adjustment from the SourceGas purchase price allocation.
[4]	Variable interest rate, based on LIBOR plus a spread.

Equity_ Stockholders Equity Rec

Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Stockholders' Equity, beginning balance		$ 1,465,867			$ 1,465,867
Noncontrolling Interest, beginning balance		0			0
Total Equity, beginning balance		1,465,867		$ 1,353,884	1,465,867	$ 1,353,884
Net income (loss) available for common stock	$ 669		$ (41,842)		40,671	(7,992)
Net Income (Loss) Including Portion Attributable to Noncontrolling Interest (Excluding Income Loss Attributable to Redeemable Noncontrolling Interest)					43,303	(7,992)
Other comprehensive income (loss)	(10,939)	(11,770)	(2,805)	990	(22,709)	(1,815)
Dividends on common stock					(43,270)	(36,292)
Share-based compensation					2,192	1,601
Issuance of common stock					55,802	0
Dividend reinvestment and stock purchase plan					1,478	1,516
Other stock transactions					(20)	(16)
Sale of noncontrolling interest					177,302
Total Stockholders' Equity, ending balance	1,562,427		1,310,886		1,562,427	1,310,886
Noncontrolling Interest, ending balance	117,518		0		117,518	0
Total Equity, ending balance	1,679,945		1,310,886		1,679,945	1,310,886
Parent [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Stockholders' Equity, beginning balance		1,465,867		1,353,884	1,465,867	1,353,884
Net income (loss) available for common stock					40,671	(7,992)
Other comprehensive income (loss)					(22,709)	(1,815)
Dividends on common stock					(43,270)	(36,292)
Share-based compensation					2,192	1,601
Issuance of common stock					55,802	0
Dividend reinvestment and stock purchase plan					1,478	1,516
Other stock transactions					(20)	(16)
Sale of noncontrolling interest					62,416
Total Stockholders' Equity, ending balance	1,562,427		1,310,886		1,562,427	1,310,886
Noncontrolling Interest [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling Interest, beginning balance		$ 0		$ 0	0	0
Net Income (Loss) Attributable to Noncontrolling Interest (Excluding Income Loss Attributable to Redeemable Noncontrolling Interest)					2,632	0
Other comprehensive income (loss)					0	0
Dividends on common stock					0	0
Share-based compensation					0	0
Issuance of common stock					0	0
Dividend reinvestment and stock purchase plan					0	0
Other stock transactions					0	0
Sale of noncontrolling interest					114,886
Noncontrolling Interest, ending balance	$ 117,518		$ 0		$ 117,518	$ 0

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	Jul. 06, 2016	Jun. 30, 2016	Jun. 30, 2016	Mar. 18, 2016
At The Market Equity Offering Program Authorized Aggregate Value				$ 200
Payments of Stock Issuance Costs		$ 0.5	$ 0.6
Common Stock [Member]
At The Market Equity Offering Program Shares Issued		809,649	930,649
At the Market Equity Program - Proceeds From Sale of Stock		$ 49	$ 56
Subsequent Event [Member] | Common Stock [Member]
At The Market Equity Offering Program Shares Issued	46,576
At the Market Equity Program - Proceeds From Sale of Stock	$ 2.9

Equity_ Variable Interest Entit

Equity: Variable Interest Entities (Details) - USD ($) $ in Thousands	Apr. 14, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage			49.90%
Sale of noncontrolling interest		$ 216,370	$ 0
Current assets		443,734	438,572	$ 822,151
Property, plant and equipment of variable interest entities, net		6,209,816	4,726,478	4,976,778
Current liabilities		1,467,896	358,508	422,029
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Sale of noncontrolling interest	$ 216,000
Current assets		12,681	0	0
Property, plant and equipment of variable interest entities, net		224,128	0	0
Current liabilities		$ 4,174	$ 0	$ 0

Risk Management Activities_ R73

Risk Management Activities: Risk Management Activities (Details) $ in Thousands		6 Months Ended			12 Months Ended
		Jun. 30, 2016USD ($)MMBTUbbl		Jun. 30, 2015USD ($)MMBTUbbl	Dec. 31, 2015USD ($)MMBTUbbl
Derivative [Line Items]
Derivative assets, non-current		$ 226		$ 0	$ 3,441
Derivative liabilities, current		28,855		3,289	2,835
Derivative liabilities, non-current		231		$ 1,433	$ 156
Oil and Gas [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months		2,700
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		$ (29,000)
Crude Oil [Member] | Swaps and Options [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities | bbl	[1]	210,000		276,000	198,000
Maximum Term Hedged in Cash Flow Hedge	[2]	30 months		18 months	24 months
Natural Gas [Member] | Swap [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU	[1]	2,530,000		4,187,500	4,392,500
Maximum Term Hedged in Cash Flow Hedge	[2]	18 months		18 months	24 months
Natural Gas, Distribution [Member] | Future [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		18,080,000		17,270,000	20,580,000
Maximum Term	[3]	54 months		66 months	60 months
Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		3,770,000		3,980,000	2,620,000
Maximum Term	[3]	20 months		9 months	3 months
Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		15,320,000		14,445,000	18,150,000
Maximum Term	[3]	54 months		54 months	60 months
Natural Gas, Distribution [Member] | Fixed for Float Swaps Purchased [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		5,029,500	[4]	0	0
Maximum Term	[3]	23 months		0 months	0 months
Natural Gas, Distribution [Member] | Natural Gas Physical Purchases [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		1,666,800		0	0
Maximum Term	[3]	9 months		0 months	0 months
Revolving Credit Facility [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Maximum Term		6 months		1 year 6 months	1 year
Derivative assets, non-current		$ 0		$ 0	$ 0
Derivative liabilities, current		1,505		3,289	2,835
Derivative liabilities, non-current		0		1,433	156
Notional Amount	[5]	$ 75,000		$ 75,000	$ 75,000
Weighted average fixed interest rate		4.97%		4.97%	4.97%
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]	2,974,500
Interest Rate Swap One [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Maximum Term		10 months			1 year 4 months
Derivative assets, non-current		$ 0			$ 3,441
Derivative liabilities, current		18,500			0
Derivative liabilities, non-current		0			0
Notional Amount	[6]	$ 250,000			$ 250,000
Weighted average fixed interest rate		2.29%			2.29%
Interest Rate Swap Two [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Maximum Term		10 months
Derivative assets, non-current		$ 0
Derivative liabilities, current		8,553
Derivative liabilities, non-current		0
Notional Amount	[6]	$ 150,000
Weighted average fixed interest rate		2.09%
[1]	Crude oil in Bbls, natural gas in MMBtus.
[2]	Term reflects the maximum forward period hedged.
[3]	Term reflects the maximum forward period hedged.
[4]	2,974,500 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.
[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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	$ (15,066)	$ (3,137)	$ (30,931)	$ (258)
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(2,386)	1,996	(5,098)	4,491
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0	0
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(12,614)	(892)	(30,665)	(1,778)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	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)	840	(1,670)	1,690	(3,107)
Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		(2,245)	(1,039)	1,520
Commodity Contract [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(2,847)
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(3,287)	3,666	(6,939)	7,598
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	$ 0	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)	395		773
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	61		151
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 0		$ 0

Fair Value Measurements_ Fair75

Fair Value Measurements: Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Assets-Transfers out of level 1 to 2	$ 0	$ 0	$ 0
Assets -Transfers out of level 2 to 1	0	0	0
Liabilities -Transfers out of level 1 to 2	0	0	0
Liabilities -Transfers out of level 2 to 1	0	0	0
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(5,325)	(12,937)	(12,127)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(14,427)	(25,141)	(19,368)
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	9,581	16,378	12,127
Derivative Liabilities, Total	43,513	28,132	24,090
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	28,558	2,991	4,722
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] | Future [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	(816)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0
Crude Oil [Member] | Future [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
Derivative Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Future [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	1,950
Derivative Liabilities, Fair Value Disclosure	157
Crude Oil [Member] | Future [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
Derivative Liabilities, Fair Value Disclosure	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		(6,309)	(5,178)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0	(112)
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
Derivative Liabilities, Fair Value Disclosure		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		6,309	5,178
Derivative Liabilities, Fair Value Disclosure		0	112
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
Derivative Liabilities, Fair Value Disclosure		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	(334)	(4,335)	(4,372)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	(556)	(498)
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	798	4,335	4,372
Derivative Liabilities, Fair Value Disclosure	71	556	498
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	(4,175)	(2,293)	(2,577)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(14,427)	(24,585)	(18,758)
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	6,833	2,293	2,577
Derivative Liabilities, Fair Value Disclosure	14,727	24,585	18,758
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	4,256	3,441	0
Derivative Liabilities, Total	29,086	2,991	4,722
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	28,558	2,991	4,722
Estimate of Fair Value Measurement [Member] | Crude Oil [Member] | Future [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	1,134
Derivative Liabilities, Fair Value Disclosure	157
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
Derivative Liabilities, Fair Value Disclosure		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	464	0	0
Derivative Liabilities, Fair Value Disclosure	71	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	2,658	0	0
Derivative Liabilities, Fair Value Disclosure	$ 300	$ 0	$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 2,630	$ 14,085	$ 9,550
Derivative Liability, Fair Value, Net	28,828	3,547	5,332
Not Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	1,626	0	0
Derivative Liability, Fair Value, Net	258	22,292	16,181
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,549	9,981	6,931
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	81	663	2,619
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	44	465	493
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	226	91	117
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	1,481	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	145	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	254	9,586	5,156
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	4	12,706	11,025
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	3,441
Derivative Asset, Fair Value, Gross Liability	0	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	28,558	2,835	3,289
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Non-current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 156	$ 1,433

Fair Value of Financial Instr77

Fair Value of Financial Instruments: Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents		$ 116,805	$ 456,535	$ 87,210	$ 21,218
Restricted cash and equivalents		1,975	1,697	2,316
Notes payable		75,000	76,800	105,760
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents		116,805	456,535	87,210
Restricted cash and equivalents		1,975	1,697	2,316
Notes payable		75,000	76,800	105,760
Long-term debt, including current maturities		3,152,090	1,853,682	1,556,370
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	[1]	116,805	456,535	87,210
Restricted Cash Fair Value Disclosure	[1]	1,975	1,697	2,316
Notes payable, Fair Value	[1]	75,000	76,800	105,760
Long-term debt, including current maturities, Fair Value	[2]	$ 3,427,587	$ 1,992,274	$ 1,700,487
[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 (L78

Other Comprehensive Income (Loss): Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 34,609	$ 19,545	$ 66,683	$ 39,455
Revenue	325,441	272,254	775,400	714,241
Fuel, purchased power and cost of natural gas sold	(84,489)	(73,824)	(256,345)	(279,151)
Operations and maintenance	112,541	90,410	219,603	183,544
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	3,592	(56,942)	47,894	(5,083)
Income tax benefit (expense)	(309)	20,317	(4,561)	2,605
Reclassification adjustments related to cash flow hedges, net of tax	669	(41,842)	40,671	(7,992)
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	(2,386)	(1,996)	(5,098)	(4,491)
Income tax benefit (expense)	882	735	1,884	1,989
Reclassification adjustments related to cash flow hedges, net of tax	(1,504)	(1,261)	(3,214)	(2,502)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	840	1,670	1,690	3,107
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	(3,287)	(3,666)	(6,939)	(7,598)
Fuel, purchased power and cost of natural gas sold	61	0	151	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)	(110)	(110)
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	988	1,410
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	878	1,300
Income tax benefit (expense)	(154)	(228)	(307)	(456)
Reclassification adjustments related to cash flow hedges, net of tax	$ 285	$ 422	$ 571	$ 844

Other Comprehensive Income (L79

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (20,825)	$ (9,055)	$ (14,054)	$ (15,044)	$ (9,055)	$ (15,044)
Other Comprehensive Income (Loss), Net of Tax	(10,939)	(11,770)	(2,805)	990	(22,709)	(1,815)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(31,764)	(20,825)	(16,859)	(14,054)	(31,764)	(16,859)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(5,331)	6,725	5,688	5,093	6,725	5,093
Other Comprehensive Income (Loss), Net of Tax	(11,224)	(12,056)	422	595
Accumulated Other Comprehensive Income (Loss), Net of Tax	(16,555)	(5,331)	6,110	5,688	(16,555)	6,110
Accumulated Defined Benefit Plans Adjustment [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax	(15,494)	(15,780)	(19,742)	(20,137)	(15,780)	(20,137)
Other Comprehensive Income (Loss), Net of Tax	285	286	(3,227)	395
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (15,209)	$ (15,494)	$ (22,969)	$ (19,742)	$ (15,209)	$ (22,969)

Supplemental Disclosure of Ca80

Supplemental Disclosure of Cash Flow Information: Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 52,917	$ 36,661
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(48,139)	(37,698)
Income taxes, net	$ (1,162)	$ (1,202)

Employee Benefit Plans_ Emplo81

Employee Benefit Plans: Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Feb. 12, 2016
Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Interest cost			$ 2,800
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 2,078	$ 1,494	4,156	$ 2,988
Interest Cost	3,936	3,880	7,872	7,760
Expected return on plan assets	(5,766)	(4,867)	(11,531)	(9,734)
Prior service cost (benefit)	15	15	30	30
Net loss (gain)	1,793	2,759	3,586	5,518
Net periodic benefit cost	2,056	3,281	4,113	6,562
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	10,200		10,200
Estimated Future Employer Contributions in Current Fiscal Year			0
Estimated Future Employer Contributions in Next Fiscal Year			10,200
Other Pension Plan, Postretirement or Supplemental Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost			300
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	878	392	907	883
Interest Cost	315	364	629	728
Prior service cost (benefit)	1	1	1	2
Net loss (gain)	207	270	414	540
Net periodic benefit cost	1,401	1,027	1,951	2,153
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	392		784
Estimated Future Employer Contributions in Current Fiscal Year			784
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	934	928
Interest Cost	485	450	970	900
Expected return on plan assets	(70)	(33)	(140)	(66)
Prior service cost (benefit)	(107)	(107)	(214)	(214)
Net loss (gain)	84	102	168	204
Net periodic benefit cost	859	$ 876	1,718	$ 1,752
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	$ 1,192		2,384
Estimated Future Employer Contributions in Current Fiscal Year			2,384
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%		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%		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%		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%		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%		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%		4.575%
Scenario, Previously Reported [Member] | Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.50%		4.50%
Scenario, Previously Reported [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.165%		4.165%

Commitments and Contingencies82

Commitments and Contingencies: Supply Commitments (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016USD ($)Bcf
Natural Gas [Member]
Unrecorded Unconditional Purchase Obligation, Due In the next Twelve Months, Physical Quantities Of Natural Gas | Bcf	0.24
Unrecorded Unconditional Purchase Obligation, Due Within Two Years, Physical Quantities Of Natural Gas | Bcf	1.20
Unrecorded Unconditional Purchase Obligation, Due Within Three Years, Physical Quantities of Natural Gas | Bcf	0.97
Natural Gas Purchases	$ 1,700
Source Gas [Member]
2,016	30,658
2,017	47,005
2,018	46,641
2,019	42,312
2,020	41,995
Thereafter	195,977
Total	404,588
Source Gas [Member] | Facilities and equipment [Member]
2,016	1,247
2,017	2,216
2,018	2,207
2,019	1,676
2,020	1,359
Thereafter	3,326
Total	12,031
Source Gas [Member] | Pipeline capacity obligations [Member]
2,016	29,411
2,017	44,789
2,018	44,434
2,019	40,636
2,020	40,636
Thereafter	192,651
Total	$ 392,557

Commitments and Contingencies83

Commitments and Contingencies: Build Transfer Agreement (Details) - Peak View Wind Project [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2016
Long-term Purchase Commitment, Amount	$ 109
Electric Utilities [Member] | Performance Guarantee [Member]
Guarantor Obligations, Maximum Exposure, Undiscounted		$ 47

Commitments and Contingencies84

Commitments and Contingencies: Commitments and Contingencies - Dividend Restrictions (Details) $ in Millions	Jun. 30, 2016USD ($)
Utilities Group [Member]
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Impairment of Assets_ Impairmen

Impairment of Assets: Impairment of Long-lived assets (Details) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016$ / bbl$ / MMcf	Jun. 30, 2015$ / bbl$ / MMcf
Impairment of Oil and Gas Properties					$ 39,993	$ 121,690
Oil and Gas [Member]
Impairment of Oil and Gas Properties	$ 11,000	$ 14,000	$ 94,000	$ 22,000
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf							2.24	3.39
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf							1.01	2.14
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl							43.12	71.68
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl							37.19	63.76
Oil and Gas [Member] | Assets Not Expected To Be Utilized In Cost Of Service Gas Program [Member]
Impairment of Oil and Gas Properties	$ 14,000

Impairment of Assets_ Equity In

Impairment of Assets: Equity Investments In Unconsolidated Subsidiaries (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Equity Method Investment, Other than Temporary Impairment	$ 0	$ 5,170	$ 0	$ 5,170
Willow Creek / Lodge Creek Pipeline And Gathering System [Member] | Oil and Gas [Member]
Equity Method Investment, Ownership Percentage		25.00%		25.00%
Equity Method Investment, Other than Temporary Impairment				$ 5,200

Income Taxes_ Income Taxes (Det

Income Taxes: Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage						49.90%
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate		35.00%		35.00%	35.00%	35.00%
State income tax (net of federal tax effect)		16.90%	[1]	2.60%	3.80%	2.40%
Percentage depletion in excess of cost	[2]	(5.90%)		0.80%	(13.50%)	9.50%
Accounting for uncertain tax positions adjustment	[3]	1.90%		(0.50%)	(10.40%)	(11.90%)
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent		(25.10%)	[4]	0.00%	(1.90%)	0.00%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Restructuring Charges, Percent					2.30%	0.00%
Effective Income Tax Rate Reconciliation, Flow Through Accounting		(10.60%)		1.00%	(1.70%)	9.50%
Inter-period tax allocation		1.70%		(6.50%)	(3.50%)	(22.60%)
Effective Income Tax Rate Reconciliation Allowance For Other Funds Used During Construction, Equity		(5.80%)		0.30%
Other tax differences		0.50%		0.00%	(0.60%)	2.70%
Effective Tax Rate		8.60%		32.70%	9.50%	24.60%
IRS Settlement [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities					$ 35
Income Tax Examination, Increase (Decrease) In Accrued Interest		$ 5.1			5.1
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority		$ 8			$ 8
[1]	The increase in state income tax expense was due primarily to a change in projections, the impact of which was more pronounced in the current period due to significantly lower consolidated pre-tax net income.
[2]	The tax benefit relates to additional percentage depletion deductions that are being claimed with respect to the oil and gas properties involving prior tax years. Such deductions are primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.
[3]	The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.
[4]	The reconciling item reflects limited liability company (LLC) income not subject to tax. Black Hills Colorado IPP went from a single member LLC wholly-owned by Black Hills Electric Generation to a partnership as a result of the sale of 49.9% of its membership interests in April 2016.

Accrued Liabilities_ Accrued 88

Accrued Liabilities: Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016		Dec. 31, 2015		Jun. 30, 2015
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 45,991		$ 43,342		$ 35,126
Accrued property taxes	33,295		32,393		26,820
Accrued payments related to litigation expenses and settlements	0		38,750		25,000
Customer deposits and prepayments	44,200		53,496		26,384
Accrued interest and contract adjustment payments	42,330		25,762		13,656
CIAC current portion	20,211	[1]	14,745	[1]	0
Other (none of which is individually significant)	32,223		23,573		33,542
Total accrued liabilities	$ 218,250		$ 232,061		$ 160,528
[1]	Prior to December 31, 2015, CIACs were classified as non-current liabilities.