Black Hills (BKH) 10-Q 5 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2017	Apr. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,461,825
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Statement [Abstract]
Revenue	$ 554,003	$ 449,959
Operating expenses:
Fuel, purchased power and cost of natural gas sold	219,777	171,856
Operations and maintenance	122,130	107,062
Depreciation, depletion and amortization	48,647	44,407
Taxes - property, production and severance	13,969	12,117
Impairment of long-lived assets	0	14,496
Other operating expenses	1,969	26,431
Total operating expenses	406,492	376,369
Operating income	147,511	73,590
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,096)	(32,074)
Allowance for funds used during construction - borrowed	486	501
Capitalized interest	169	235
Interest income	41	655
Allowance for funds used during construction - equity	492	707
Other income (expense), net	(102)	688
Total other income (expense), net	(34,010)	(29,288)
Income before income taxes	113,501	44,302
Income tax benefit (expense)	(33,355)	(4,252)
Net income	80,146	40,050
Net income attributable to noncontrolling interest	(3,623)	(48)
Net income available for common stock	$ 76,523	$ 40,002
Earnings per share of common stock:
Earnings (loss) per share, Basic (usd per share)	$ 1.44	$ 0.78
Earnings (loss) per share, Diluted (usd per share)	$ 1.39	$ 0.77
Weighted average common shares outstanding:
Basic (in shares)	53,152	51,044
Diluted (in shares)	54,932	51,858
Dividends declared per share of common stock (usd per share)	$ 0.445	$ 0.420

Condensed Consolidated Stateme3

Condensed Consolidated Statement of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income (loss)	$ 80,146	$ 40,050
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost	(31)	(36)
Reclassification adjustments of benefit plan liability - net gain (loss)	260	322
Other comprehensive income (loss), net of tax	1,153	(11,770)
Comprehensive income (loss)	81,299	28,280
Less: comprehensive income attributable to noncontrolling interest	(3,623)	(48)
Comprehensive income (loss) available for common stock	77,676	28,232
Interest Rate Swap
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	58	(9,796)
Reclassification of net realized (gains) losses	463	(1,111)
Commodity Contract
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	584	1,152
Reclassification of net realized (gains) losses	$ (181)	$ (2,301)

Condensed Consolidated Stateme4

Condensed Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reclassification adjustment of benefit plan - prior service cost, (tax) benefit	$ 17	$ 19
Reclassification adjustment of benefit plan liabilities, (tax) benefit	(154)	(172)
Interest Rate Swap
Net unrealized gains/losses, (tax) benefit	(32)	5,251
Reclassification of net realized gains/losses, (tax) benefit	(249)	598
Commodity Contract
Net unrealized gains/losses, (tax) benefit	(342)	(675)
Reclassification of net realized gains/losses, (tax) benefit	$ 106	$ 1,348

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Current assets:
Cash and cash equivalents	$ 11,353	$ 13,580	$ 26,046
Restricted cash and equivalents	2,409	2,274	1,839
Accounts receivable, net	224,714	263,289	206,276
Materials, supplies and fuel	84,484	107,210	78,176
Derivative assets, current	1,541	4,138	1,486
Regulatory assets, current	53,476	49,260	54,108
Other current assets	23,425	27,063	34,287
Total current assets	401,402	466,814	402,218
Investments	12,712	12,561	12,126
Property, plant and equipment	6,436,610	6,412,223	6,063,943
Less: accumulated depreciation and depletion	(1,943,538)	(1,943,234)	(1,742,070)
Total property, plant and equipment, net	4,493,072	4,468,989	4,321,873
Other assets:
Goodwill	1,299,454	1,299,454	1,306,169
Intangible assets, net	8,182	8,392	10,957
Regulatory assets, non-current	249,113	246,882	239,023
Derivative assets, non-current	9	222	85
Other assets, non-current	11,905	12,130	11,274
Total other assets, non-current	1,568,663	1,567,080	1,567,508
TOTAL ASSETS	6,475,849	6,515,444	6,303,725
Current liabilities:
Accounts payable	105,074	153,477	100,756
Accrued liabilities	203,467	244,034	272,181
Derivative liabilities, current	464	2,459	3,965
Accrued income taxes, net	3,726	12,552	10,899
Regulatory liabilities, current	22,118	13,067	35,933
Notes payable	50,950	96,600	215,600
Current maturities of long-term debt	5,743	5,743	0
Total current liabilities	391,542	527,932	639,334
Long-term debt	3,210,730	3,211,189	3,159,055
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	577,211	535,606	500,202
Derivative liabilities, non-current	176	274	14,522
Regulatory liabilities, non-current	196,538	193,689	200,337
Benefit plan liabilities	174,827	173,682	181,270
Other deferred credits and other liabilities	135,847	138,643	124,181
Total deferred credits and other liabilities	1,084,599	1,041,894	1,020,512
Commitments and contingencies (See Notes 8, 10, 15, 16)
Redeemable noncontrolling interest	0	4,295	4,141
Equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 53,502,252; 53,397,467; and 51,477,472 shares, respectively	53,502	53,397	51,477
Additional paid-in capital	1,143,102	1,138,982	960,605
Retained earnings	513,885	457,934	490,999
Treasury stock, at cost – 41,443; 15,258; and 30,903 shares, respectively	(2,443)	(791)	(1,573)
Accumulated other comprehensive income (loss)	(33,730)	(34,883)	(20,825)
Total stockholders’ equity	1,674,316	1,614,639	1,480,683
Noncontrolling interest	114,662	115,495	0
Total equity	1,788,978	1,730,134	1,480,683
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$ 6,475,849	$ 6,515,444	$ 6,303,725

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (unaudited) (Parentheticals) - $ / shares	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	53,502,252	53,397,467	51,477,472
Treasury Stock, Shares	41,443	15,258	30,903
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating activities:
Net income (loss)	$ 80,146	$ 40,050
Net income (loss) available for common stock	76,523	40,002
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	48,647	44,407
Deferred financing cost amortization	1,690	1,666
Impairment of long-lived assets	0	14,496
Stock compensation	3,091	4,461
Deferred income taxes	42,195	32,579
Employee benefit plans	3,242	3,466
Other adjustments, net	(2,303)	(5,000)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	22,445	25,822
Accounts receivable, unbilled revenues and other operating assets	41,052	27,559
Accounts payable and other operating liabilities	(99,482)	(73,355)
Regulatory assets - current	236	12,856
Regulatory liabilities - current	9,083	11,613
Other operating activities, net	(3,202)	(7,489)
Net cash provided by (used in) operating activities	146,840	133,083
Investing activities:
Property, plant and equipment additions	(69,309)	(83,885)
Acquisition, net of long term debt assumed	0	(1,132,318)
Other investing activities	(185)	(329)
Net cash provided by (used in) investing activities	(69,494)	(1,216,532)
Financing activities:
Dividends paid on common stock	(23,754)	(21,537)
Common stock issued	2,171	7,821
Net (payments) borrowings on short-term debt	(45,650)	138,800
Long-term debt - issuances	0	545,959
Long-term debt - repayments	(1,436)	0
Distributions to noncontrolling interest	(4,349)	0
Other financing activities	(6,555)	(2,409)
Net cash provided by (used in) financing activities	(79,573)	668,634
Net change in cash and cash equivalents	(2,227)	(414,815)
Cash and cash equivalents, beginning of period	13,580	440,861
Cash and cash equivalents, end of period	$ 11,353	$ 26,046

Management's Statement_

Management's Statement:	3 Months Ended
	Mar. 31, 2017
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 2016 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. Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2017 , December 31, 2016 , and March 31, 2016 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2017 and March 31, 2016 , and our financial condition as of March 31, 2017 , December 31, 2016 , and March 31, 2016 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. March 31, 2017 reflects a full quarter of activity from the SourceGas acquisition on February 12, 2016, as compared to March 31, 2016 which reflects a partial quarter. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted. Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash. The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $21 million as of March 31, 2016, and decreased net cash flows provided by operations by $5.3 million for the three months ended March 31, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the condensed consolidated balance sheet as of March 31, 2016 and to the condensed consolidated statements of cash flows for the three months ended March 31, 2016. There is no impact to the Condensed Consolidated Statements of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported. Recently Issued and Adopted Accounting Standards Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost” . The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently assessing the changes to the standard. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). T his ASU requires changes in the pres entation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15 , 2017. We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting . This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff-based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

Acquisition_

Acquisition:	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Acquisition	ACQUISITION 2016 Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas (now referred to as Black Hills Gas Holdings). Net cash paid at acquisition was $1.1 billion , and included the assumption of $760 million of long-term debt. We finalized our purchase price allocation at December 31, 2016. See Note 2 of our Notes to the Consolidated Financial Statements in our 2016 Annual Report on Form 10-K for more details. Pro Forma Results The following unaudited pro forma financial information reflects the consolidated results of operations as if the SourceGas Acquisition had taken place on January 1, 2015. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results. The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three months ended March 31, 2016 exclude approximately $16 million of after-tax transaction costs, professional fees, employee related expenses and other miscellaneous costs. Pro Forma Results Three Months Ended March 31, 2016 (in thousands, except per share amounts) Revenue $528,921 Net income (loss) available for common stock $66,690 Earnings (loss) per share, Basic $1.31 Earnings (loss) per share, Diluted $1.29 Redemption of seller’s noncontrolling interest As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder of the 0.5% retained interest. The terms of the agreement provided us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million .

Business Segment Information_

Business Segment Information:	3 Months Ended
	Mar. 31, 2017
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 were as follows (in thousands): Three Months Ended March 31, 2017 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 172,170 $ 3,854 $ 22,230 Gas (a) 364,901 9 46,010 Power Generation (b) 2,102 21,465 6,530 Mining 8,355 8,191 2,890 Oil and Gas 6,475 — (2,951 ) Corporate activities (c) (d) — — 1,814 Inter-company eliminations — (33,519 ) — Total $ 554,003 $ — $ 76,523 Three Months Ended March 31, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric . $ 163,531 $ 3,745 $ 19,215 Gas (a) 268,667 1,806 31,927 Power Generation 1,852 21,456 8,582 Mining 7,534 8,748 2,938 Oil and Gas (e) 8,375 — (7,024 ) Corporate activities (c) (d) — — (15,636 ) Inter-company eliminations — (35,755 ) — Total $ 449,959 $ — $ 40,002 ___________ (a) Gas Utility revenue increased for the three months ended March 31, 2017 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016. (b) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.5 million for the three months ended March 31, 2017 . (c) Net income (loss) available for common stock for the three months ended March 31, 2017 and March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.9 million and $15 million , respectively, and after-tax internal labor costs attributable to the acquisition of $0.3 million and $3.8 million , respectively. (d) Net income (loss) available for common stock for the three months ended March 31, 2017 included a net tax benefit of approximately $3.2 million comprised of a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years and a tax benefit of $1.8 million driven primarily by the adjustment to the projected annual effective tax rate. Net income (loss) available for common stock for the three months ended March 31, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18. (e) Net income (loss) available for common stock for the three months ended March 31, 2016 includes a non-cash after-tax impairment of oil and gas properties of $8.8 million . See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q. Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: March 31, 2017 December 31, 2016 March 31, 2016 Segment: Electric (a) $ 2,872,989 $ 2,859,559 $ 2,703,774 Gas 3,260,989 3,307,967 3,141,897 Power Generation (a) 72,540 73,445 74,403 Mining 64,973 67,347 73,878 Oil and Gas (b) 95,212 96,435 197,291 Corporate activities 109,146 110,691 112,482 Total assets $ 6,475,849 $ 6,515,444 $ 6,303,725 __________ (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) As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $107 million for the year ended December 31, 2016 and $14 million for the three months ended March 31, 2016 . See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable_

Accounts Receivable:	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts March 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,679 $ 30,778 $ (639 ) $ 69,818 Gas Utilities 98,027 51,926 (3,646 ) 146,307 Power Generation 1,353 — — 1,353 Mining 3,197 — — 3,197 Oil and Gas 2,952 — (13 ) 2,939 Corporate 1,100 — — 1,100 Total $ 146,308 $ 82,704 $ (4,298 ) $ 224,714 Accounts Unbilled Less Allowance for Accounts December 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Oil and Gas 3,991 — (13 ) 3,978 Corporate 2,228 — — 2,228 Total $ 140,889 $ 124,792 $ (2,392 ) $ 263,289 Accounts Unbilled Less Allowance for Accounts March 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,981 $ 32,660 $ (772 ) $ 73,869 Gas Utilities 73,259 55,014 (4,363 ) 123,910 Power Generation 1,210 — — 1,210 Mining 2,484 — — 2,484 Oil and Gas 2,395 — (13 ) 2,382 Corporate 2,421 — — 2,421 Total $ 123,750 $ 87,674 $ (5,148 ) $ 206,276

Regulatory Accounting_

Regulatory Accounting:	3 Months Ended
	Mar. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Accounting	REGULATORY ACCOUNTING We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) March 31, 2017 December 31, 2016 March 31, 2016 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 23,473 $ 17,491 $ 24,479 Deferred gas cost adjustments (a)(d) 1 8,991 15,329 14,895 Gas price derivatives (a) 4 11,520 8,843 20,324 Deferred taxes on AFUDC (b) 45 14,976 15,227 13,677 Employee benefit plans (c) 12 109,172 108,556 111,661 Environmental (a) subject to approval 1,089 1,108 1,162 Asset retirement obligations (a) 44 507 505 487 Loss on reacquired debt (a) 30 19,869 20,188 3,097 Renewable energy standard adjustment (b) 5 1,138 1,605 4,507 Deferred taxes on flow through accounting (c) 35 39,152 37,498 30,614 Decommissioning costs (e) 10 15,745 16,859 18,134 Gas supply contract termination 5 24,178 26,666 30,613 Other regulatory assets (a) 15 32,779 26,267 19,481 $ 302,589 $ 296,142 $ 293,131 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 21,507 $ 10,368 $ 40,797 Employee benefit plans (c) 12 67,973 68,654 63,580 Cost of removal (a) 44 122,197 118,410 123,076 Revenue subject to refund 1 1,345 2,485 1,131 Other regulatory liabilities (c) 25 5,634 6,839 7,686 $ 218,656 $ 206,756 $ 236,270 __________ (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) South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants for which we are allowed a rate of return, in addition to recovery of costs.

Materials, Supplies and Fuel_

Materials, Supplies and Fuel:	3 Months Ended
	Mar. 31, 2017
Inventory, Net [Abstract]
Materials, Supplies and Fuel	MATERIALS, SUPPLIES AND FUEL The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Materials and supplies $ 71,823 $ 68,456 $ 66,542 Fuel - Electric Utilities 3,433 3,667 5,365 Natural gas in storage held for distribution 9,228 35,087 6,269 Total materials, supplies and fuel $ 84,484 $ 107,210 $ 78,176

Earnings Per Share_

Earnings Per Share:	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands): Three Months Ended March 31, 2017 2016 Net income (loss) available for common stock $ 76,523 $ 40,002 Weighted average shares - basic 53,152 51,044 Dilutive effect of: Equity Units (a) 1,595 720 Equity compensation 185 94 Weighted average shares - diluted 54,932 51,858 __________ (a) Calculated using the treasury stock method. The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended March 31, 2017 2016 Equity compensation — 74 Anti-dilutive shares — 74

Notes Payable_

Notes Payable:	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Notes Payable	NOTES PAYABLE We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 28,100 $ 96,600 $ 36,000 $ 215,600 $ 24,000 CP Program 50,950 — — — — — Total $ 50,950 $ 28,100 $ 96,600 $ 36,000 $ 215,600 $ 24,000 Revolving Credit Facility and CP Program On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one -year extension options (subject to consent from lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase total commitments of the facility up to $1.0 billion . Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250% , 1.250% , and 1.250% , respectively, at March 31, 2017 . A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility. On December 22, 2016, we implemented a $750 million , unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million . The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net amount borrowed under the CP Program during the three months ended March 31, 2017 and our notes outstanding as of March 31, 2017 were $51 million . As of March 31, 2017, the weighted average interest rate on CP Program borrowings was 1.27% . Debt Covenants On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 . Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: As of March 31, 2017 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 61% Less than 65% As of March 31, 2017 , we were in compliance with this covenant.

Equity_

Equity:	3 Months Ended
	Mar. 31, 2017
Statement of Stockholders' Equity [Abstract]
Equity	EQUITY A summary of the changes in equity is as follows: Three Months Ended March 31, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 76,523 3,516 80,039 Other comprehensive income (loss) 1,153 — 1,153 Dividends on common stock (23,754 ) — (23,754 ) Share-based compensation 2,392 — 2,392 Dividend reinvestment and stock purchase plan 748 — 748 Redeemable noncontrolling interest (1,096 ) — (1,096 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (3 ) — (3 ) Distribution to noncontrolling interest — (4,349 ) (4,349 ) Balance at March 31, 2017 $ 1,674,316 $ 114,662 $ 1,788,978 Three Months Ended March 31, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 $ — $ 1,465,867 Net income (loss) 40,002 — 40,002 Other comprehensive income (loss) (11,770 ) — (11,770 ) Dividends on common stock (21,543 ) — (21,543 ) Share-based compensation 561 — 561 Issuance of common stock 6,824 — 6,824 Dividend reinvestment and stock purchase plan 755 — 755 Other stock transactions (13 ) — (13 ) Balance at March 31, 2016 $ 1,480,683 $ — $ 1,480,683 At-the-Market Equity Offering Program On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million . The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares during the three months ended March 31, 2017. During the three months ended March 31, 2016, we issued 121,000 common shares for $7.0 million , net of $0.1 million in fees and issuance costs with settlement dates through March 31, 2016 under the ATM equity offering program. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns a 200 MW , combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. This partial sale was required to be recorded as an equity transaction with no resulting gain or loss on the sale. Further, 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: March 31, 2017 December 31, 2016 March 31, 2016 (in thousands) Assets Current assets $ 12,167 $ 12,627 $ — Property, plant and equipment of variable interest entities, net $ 217,083 $ 218,798 $ — Liabilities Current liabilities $ 3,464 $ 4,342 $ —

Risk Management Activities_

Risk Management Activities:	3 Months Ended
	Mar. 31, 2017
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 2016 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. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based on payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income and Condensed Consolidated Statements of Comprehensive Income are detailed below and in Note 11 . 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, swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on our futures and swaps. 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. 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: March 31, 2017 December 31, 2016 March 31, 2016 Crude Oil Futures Crude Oil Options Natural Gas Futures and Swaps Crude Oil Futures Crude Oil Options Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 90,000 27,000 1,890,000 108,000 36,000 2,700,000 159,000 3,447,500 Maximum terms in months (b) 21 9 9 24 12 12 21 21 __________ (a) Crude oil futures and call options in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged. Based on March 31, 2017 prices, a $0.3 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, or the Condensed Consolidated Statements of Comprehensive Income. We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from April 2017 through May 2019. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold in the accompanying Condensed Consolidated Statements of Income. Effectiveness of our hedging position is evaluated at least quarterly. 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: March 31, 2017 December 31, 2016 March 31, 2016 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 12,330,000 45 14,770,000 48 18,270,000 57 Natural gas options purchased, net 500,000 21 3,020,000 5 990,000 21 Natural gas basis swaps purchased 11,230,000 45 12,250,000 48 16,810,000 57 Natural gas over-the-counter swaps, net (b) 3,165,952 26 4,622,302 28 1,557,011 23 Natural gas physical contracts, net 3,015,234 12 21,504,378 10 2,135,050 12 __________ (a) Term reflects the maximum forward period hedged. (b) 1,180,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased. Financing Activities In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to reduce the interest rate risk associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten -year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten -year life of the $400 million unsecured senior note issued on August 19, 2016. Amortization of approximately $2.9 million , including the amortization of the $28 million loss currently deferred in AOCI will be recognized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. The ineffective portion of $1.0 million , related to the timing of the debt issuance, was recognized in earnings as a component of interest expense. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Designated Designated (a) Designated (b) Designated (b) Designated (a) Notional $ — $ 50,000 $ 150,000 $ 250,000 $ 75,000 Weighted average fixed interest rate — % 4.94 % 2.09 % 2.29 % 4.97 % Maximum terms in months 0 1 13 13 10 Derivative assets, non-current $ — $ — — $ — $ — Derivative liabilities, current $ — $ 90 — $ — $ 2,290 Derivative liabilities, non-current $ — $ — $ 3,785 $ 10,693 $ — __________ (a) The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings . (b) These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt. Cash Flow Hedges The impacts of cash flow hedges on our Condensed Consolidated Statements of Income is presented below for the three months ended March 31, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. Three Months Ended March 31, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (712 ) Interest expense $ — Commodity derivatives Revenue 229 Revenue — Commodity derivatives Fuel, purchased power and cost of natural gas sold 58 Fuel, purchased power and cost of natural gas sold — Total $ (425 ) $ — Three Months Ended March 31, 2016 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ 1,709 Interest expense $ — Commodity derivatives Revenue 3,592 Revenue $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold 57 Fuel, purchased power and cost of natural gas sold — Total $ 5,358 $ — The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three months ended March 31 , 2017 and 2016 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income as incurred. Three Months Ended 2017 2016 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ 90 $ (15,047 ) Forward commodity contracts 926 1,827 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 712 (1,709 ) Forward commodity contracts (287 ) (3,649 ) Total other comprehensive income (loss) from hedging $ 1,441 $ (18,578 ) Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three months ended March 31 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. Three Months Ended March 31, 2017 2016 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Revenue $ 117 $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (809 ) 634 $ (692 ) $ 634 As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets. The net unrealized losses included in our Regulatory assets related to the hedges in our Utilities were $12 million , $8.8 million and $20 million at March 31, 2017 , December 31, 2016 and March 31, 2016 , respectively.

Fair Value Measurements_

Fair Value Measurements:	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Derivative Financial Instruments The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information, see Notes 1, 9, 10 and 11 to the Consolidated Financial Statements included in our 2016 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, basis swaps and call options. 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 and options (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA component based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Corporate Activities: • As of March 31, 2017 , we no longer have derivatives within our corporate activities as our interest rate swaps matured in January 2017. The interest rate swaps that were in place prior to January 2017 were valued using the market approach. We established fair value by obtaining price quotes directly from the counterparty which were based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty was 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 included a CVA component. The CVA considered 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 utilized 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 took into account our credit ratings, and the credit rating of our counterparty. Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of March 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 1,536 $ — $ (977 ) $ 559 Commodity derivatives — Utilities — 2,642 — (1,651 ) 991 Total $ — $ 4,178 $ — $ (2,628 ) $ 1,550 Liabilities: Commodity derivatives — Oil and Gas $ — $ 434 $ — $ — $ 434 Commodity derivatives — Utilities — 13,139 — (12,933 ) 206 Total $ — $ 13,573 $ — $ (12,933 ) $ 640 As of December 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 2,886 $ — $ (2,733 ) $ 153 Commodity derivatives —Utilities — 7,469 — (3,262 ) 4,207 Interest Rate Swaps — — — — — Total $ — $ 10,355 $ — $ (5,995 ) $ 4,360 Liabilities: Commodity derivatives — Oil and Gas $ — $ 1,586 $ — $ — $ 1,586 Commodity derivatives — Utilities — 12,201 — (11,144 ) 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 13,877 $ — $ (11,144 ) $ 2,733 As of March 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 8,429 $ — $ (8,429 ) $ — Commodity derivatives — Utilities — 3,070 — (1,499 ) 1,571 Total $ — $ 11,499 $ — $ (9,928 ) $ 1,571 Liabilities: Commodity derivatives — Oil and Gas $ — $ 251 $ — $ (251 ) $ — Commodity derivatives — Utilities — 23,428 — (21,709 ) 1,719 Interest rate swaps — 16,768 — — 16,768 Total $ — $ 40,447 $ — $ (21,960 ) $ 18,487 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, 2016 , and March 31, 2016 , 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 10 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 March 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 722 $ — Commodity derivatives Derivative liabilities — current — 305 Commodity derivatives Derivative liabilities — non-current — 71 Total derivatives designated as hedges $ 722 $ 376 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 819 $ — Commodity derivatives Derivative assets — non-current 9 — Commodity derivatives Derivative liabilities — current — 159 Commodity derivatives Derivative liabilities — non-current — 105 Total derivatives not designated as hedges $ 828 $ 264 As of December 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 1,161 $ — Commodity derivatives Derivative assets — non-current 124 — Commodity derivatives Derivative liabilities — current — 1,090 Commodity derivatives Derivative liabilities — non-current — 238 Interest rate swaps Derivative liabilities — current — 90 Total derivatives designated as hedges $ 1,285 $ 1,418 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 2,977 $ — Commodity derivatives Derivative assets — non-current 98 — Commodity derivatives Derivative liabilities — current — 1,279 Commodity derivatives Derivative liabilities — non-current — 36 Total derivatives not designated as hedges $ 3,075 $ 1,315 As of March 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 159 $ — Commodity derivatives Derivative assets — non-current 6 — Commodity derivatives Derivative liabilities — current — 770 Commodity derivatives Derivative liabilities — non-current — 33 Interest rate swaps Derivative liabilities — current — 2,290 Interest rate swaps Derivative liabilities — non-current — 14,478 Total derivatives designated as hedges $ 165 $ 17,571 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,327 $ — Commodity derivatives Derivative assets — non-current 79 — Commodity derivatives Derivative liabilities — current — 905 Commodity derivatives Derivative liabilities — non-current — 11 Total derivatives not designated as hedges $ 1,406 $ 916

Fair Value of Financial Instrum

Fair Value of Financial Instruments:	3 Months Ended
	Mar. 31, 2017
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 11 , were as follows (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 11,353 $ 11,353 $ 13,580 $ 13,580 $ 26,046 $ 26,046 Restricted cash and equivalents (a) $ 2,409 $ 2,409 $ 2,274 $ 2,274 $ 1,839 $ 1,839 Notes payable (b) $ 50,950 $ 50,950 $ 96,600 $ 96,600 $ 215,600 $ 215,600 Long-term debt, including current maturities, net of deferred financing costs (c) $ 3,216,473 $ 3,388,809 $ 3,216,932 $ 3,351,305 $ 3,159,055 $ 3,392,652 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Other Comprehensive Income (Los

Other Comprehensive Income (Loss):	3 Months Ended
	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss)	OTHER COMPREHENSIVE INCOME (LOSS) We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three months ended March 31, 2017 March 31, 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (712 ) $ 1,709 Commodity contracts Revenue 229 3,592 Commodity contracts Fuel, purchased power and cost of natural gas sold 58 57 (425 ) 5,358 Income tax Income tax benefit (expense) 143 (1,946 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (282 ) $ 3,412 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 48 $ 55 Actuarial gain (loss) Operations and maintenance (414 ) (494 ) (366 ) (439 ) Income tax Income tax benefit (expense) 137 153 Total reclassification adjustments related to defined benefit plans, net of tax $ (229 ) $ (286 ) Total reclassifications $ (511 ) $ 3,126 Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications 58 584 — 642 Amounts reclassified from AOCI 463 (181 ) 229 511 Ending Balance March 31, 2017 $ (17,588 ) $ 170 $ (16,312 ) $ (33,730 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (9,796 ) 1,152 — (8,644 ) Amounts reclassified from AOCI (1,111 ) (2,301 ) 286 (3,126 ) Ending Balance March 31, 2016 $ (11,248 ) $ 5,917 $ (15,494 ) $ (20,825 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information:	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Three Months Ended March 31, 2017 March 31, 2016 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 28,358 $ 30,260 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (36,362 ) $ (15,528 ) Income taxes, net $ 13 $ —

Employee Benefit Plans_

Employee Benefit Plans:	3 Months Ended
	Mar. 31, 2017
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 2,005 $ 2,078 Interest cost 3,880 3,936 Expected return on plan assets (6,129 ) (5,765 ) Prior service cost 14 15 Net loss (gain) 1,002 1,793 Net periodic benefit cost $ 772 $ 2,057 Defined Benefit Postretirement Healthcare Plans The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 603 $ 467 Interest cost 533 485 Expected return on plan assets (79 ) (70 ) Prior service cost (benefit) (109 ) (107 ) Net loss (gain) 125 84 Net periodic benefit cost $ 1,073 $ 859 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 827 $ 29 Interest cost 319 314 Prior service cost 1 — Net loss (gain) 250 207 Net periodic benefit cost $ 1,397 $ 550 Contributions Contributions to the Defined Benefit Pension Plan 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 made in 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands): Contributions Made Additional Contributions Contributions Three Months Ended March 31, 2017 Anticipated for 2017 Anticipated for 2018 Defined Benefit Pension Plans $ — $ 10,200 $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,270 $ 3,811 $ 5,115 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 396 $ 1,187 $ 1,682

Commitments and Contingencies_

Commitments and Contingencies:	3 Months Ended
	Mar. 31, 2017
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 2016 Annual Report on Form 10-K except for those described below. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2017 , we were in compliance with the debt covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions and financing agreements. As of March 31, 2017 , the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million .

Impairment of Assets_

Impairment of Assets:	3 Months Ended
	Mar. 31, 2017
Asset Impairment Charges [Abstract]
Impairment of Assets	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. At March 31, 2017 , the average NYMEX natural gas price was $2.73 per Mcf, adjusted to $2.48 per Mcf at the wellhead; the average NYMEX crude oil price was $47.61 per barrel, adjusted to $42.81 per barrel at the wellhead. There were no impairments for the three months ended March 31, 2017 . At March 31, 2016 , the average NYMEX natural gas price was $2.40 per Mcf, adjusted to $1.13 per Mcf at the wellhead; the average NYMEX crude oil price was $46.26 per barrel, adjusted to $39.80 per barrel at the wellhead. During the three months ended March 31, 2016 , we recorded a pre-tax non-cash impairment of oil and gas assets included in our Oil and Gas segment of $14 million .

Income Taxes_

Income Taxes:	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES The effective tax rate differs from the federal statutory rate as follows: Three Months Ended March 31, Tax (benefit) expense 2017 2016 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) 1.3 2.6 Percentage depletion in excess of cost (b) (0.4 ) (14.1 ) Accounting for uncertain tax positions adjustment (c) — (11.4 ) Noncontrolling interest (d) (1.1 ) — IRC 172(f) carryback claim (e) (1.8 ) — Tax Credits (f) (1.2 ) — Effective tax rate adjustment (g) (2.4 ) (4.0 ) Transaction costs — 2.5 Other tax differences — (1.0 ) 29.4 % 9.6 % __________ (a) The state income tax benefit is primarily attributable to favorable flow-through adjustments. (b) The tax benefit for the three months ended March 31, 2016 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. (c) The tax benefit for the three months ended March 31, 2016 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. (d) Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9 percent of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. (e) In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company's accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (f) The tax credits for the three months ended March 31, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. Peak View began generating production tax credits during the fourth quarter of 2016. (g) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270. 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:	3 Months Ended
	Mar. 31, 2017
Payables and Accruals [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES The following amounts by major classification are included in Accrued liabilities in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 (b) Accrued employee compensation, benefits and withholdings $ 47,361 $ 56,926 $ 50,345 Accrued property taxes 41,675 40,004 40,638 Gas-gathering contract (a) — — 39,944 Customer deposits and prepayments 39,288 51,628 42,573 Accrued interest and contract adjustment payments 30,488 45,503 33,381 CIAC current portion 1,575 — 20,466 Other (none of which is individually significant) 43,080 49,973 44,834 Total accrued liabilities $ 203,467 $ 244,034 $ 272,181 _________ (a) This contract was settled on April 29, 2016. (b) To conform with the March 31, 2017 and December 31, 2016 presentation of accrued liabilities, the accrued employee compensation, benefits and withholdings, customer deposits and prepayments, accrued interest and contract adjustment payments and other line items presented above have been reclassified within the disclosure. These changes had no effect on total accrued liabilities.

Management's Statement_ (Polici

Management's Statement: (Policies)	3 Months Ended
	Mar. 31, 2017
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.
Use of Estimates and Basis of Presentation	Use of Estimates and Basis of Presentation The information furnished in the accompanying Condensed Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2017 , December 31, 2016 , and March 31, 2016 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2017 and March 31, 2016 , and our financial condition as of March 31, 2017 , December 31, 2016 , and March 31, 2016 , are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. March 31, 2017 reflects a full quarter of activity from the SourceGas acquisition on February 12, 2016, as compared to March 31, 2016 which reflects a partial quarter. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.
Revisions	Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash. The Company has banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $21 million as of March 31, 2016, and decreased net cash flows provided by operations by $5.3 million for the three months ended March 31, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the condensed consolidated balance sheet as of March 31, 2016 and to the condensed consolidated statements of cash flows for the three months ended March 31, 2016. There is no impact to the Condensed Consolidated Statements of Income or the Condensed Consolidated Statements of Comprehensive Income for any period reported.
Recently Issued and Adopted Accounting Standards	Recently Issued and Adopted Accounting Standards Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost” . The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net period pension and post-retirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently assessing the changes to the standard. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). T his ASU requires changes in the pres entation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15 , 2017. We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting . This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment to retained earnings as of the date of adoption of $3.2 million in the Condensed Consolidated Balance Sheets, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff-based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

Acquisition_ (Tables)

Acquisition: (Tables)	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Business Combination, Pro Forma Information	The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the three months ended March 31, 2016 exclude approximately $16 million of after-tax transaction costs, professional fees, employee related expenses and other miscellaneous costs. Pro Forma Results Three Months Ended March 31, 2016 (in thousands, except per share amounts) Revenue $528,921 Net income (loss) available for common stock $66,690 Earnings (loss) per share, Basic $1.31 Earnings (loss) per share, Diluted $1.29

Business Segment Information_ (

Business Segment Information: (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting Information, Additional Information [Abstract]
Segment Reporting	Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income were as follows (in thousands): Three Months Ended March 31, 2017 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric $ 172,170 $ 3,854 $ 22,230 Gas (a) 364,901 9 46,010 Power Generation (b) 2,102 21,465 6,530 Mining 8,355 8,191 2,890 Oil and Gas 6,475 — (2,951 ) Corporate activities (c) (d) — — 1,814 Inter-company eliminations — (33,519 ) — Total $ 554,003 $ — $ 76,523 Three Months Ended March 31, 2016 External Operating Revenue Inter-company Operating Revenue Net Income (Loss) Available for Common Stock Segment: Electric . $ 163,531 $ 3,745 $ 19,215 Gas (a) 268,667 1,806 31,927 Power Generation 1,852 21,456 8,582 Mining 7,534 8,748 2,938 Oil and Gas (e) 8,375 — (7,024 ) Corporate activities (c) (d) — — (15,636 ) Inter-company eliminations — (35,755 ) — Total $ 449,959 $ — $ 40,002 ___________ (a) Gas Utility revenue increased for the three months ended March 31, 2017 compared to the same periods in the prior year primarily due to the addition of the SourceGas utilities on February 12, 2016. (b) Net income (loss) available for common stock is net of net income attributable to noncontrolling interests of $3.5 million for the three months ended March 31, 2017 . (c) Net income (loss) available for common stock for the three months ended March 31, 2017 and March 31, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.9 million and $15 million , respectively, and after-tax internal labor costs attributable to the acquisition of $0.3 million and $3.8 million , respectively. (d) Net income (loss) available for common stock for the three months ended March 31, 2017 included a net tax benefit of approximately $3.2 million comprised of a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years and a tax benefit of $1.8 million driven primarily by the adjustment to the projected annual effective tax rate. Net income (loss) available for common stock for the three months ended March 31, 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. See Note 18. (e) Net income (loss) available for common stock for the three months ended March 31, 2016 includes a non-cash after-tax impairment of oil and gas properties of $8.8 million . See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
Reconciliation of Assets from Segment to Consolidated	Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Total Assets (net of inter-company eliminations) as of: March 31, 2017 December 31, 2016 March 31, 2016 Segment: Electric (a) $ 2,872,989 $ 2,859,559 $ 2,703,774 Gas 3,260,989 3,307,967 3,141,897 Power Generation (a) 72,540 73,445 74,403 Mining 64,973 67,347 73,878 Oil and Gas (b) 95,212 96,435 197,291 Corporate activities 109,146 110,691 112,482 Total assets $ 6,475,849 $ 6,515,444 $ 6,303,725 __________ (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) As a result of continued low commodity prices and our decision to divest non-core oil and gas assets, we recorded non-cash impairments of $107 million for the year ended December 31, 2016 and $14 million for the three months ended March 31, 2016 . See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable_ (Tables)

Accounts Receivable: (Tables)	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: Accounts Unbilled Less Allowance for Accounts March 31, 2017 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 39,679 $ 30,778 $ (639 ) $ 69,818 Gas Utilities 98,027 51,926 (3,646 ) 146,307 Power Generation 1,353 — — 1,353 Mining 3,197 — — 3,197 Oil and Gas 2,952 — (13 ) 2,939 Corporate 1,100 — — 1,100 Total $ 146,308 $ 82,704 $ (4,298 ) $ 224,714 Accounts Unbilled Less Allowance for Accounts December 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Oil and Gas 3,991 — (13 ) 3,978 Corporate 2,228 — — 2,228 Total $ 140,889 $ 124,792 $ (2,392 ) $ 263,289 Accounts Unbilled Less Allowance for Accounts March 31, 2016 Receivable, Trade Revenue Doubtful Accounts Receivable, net Electric Utilities $ 41,981 $ 32,660 $ (772 ) $ 73,869 Gas Utilities 73,259 55,014 (4,363 ) 123,910 Power Generation 1,210 — — 1,210 Mining 2,484 — — 2,484 Oil and Gas 2,395 — (13 ) 2,382 Corporate 2,421 — — 2,421 Total $ 123,750 $ 87,674 $ (5,148 ) $ 206,276

Regulatory Accounting_ (Tables)

Regulatory Accounting: (Tables)	3 Months Ended
	Mar. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities (in thousands): Maximum As of As of As of Amortization (in years) March 31, 2017 December 31, 2016 March 31, 2016 Regulatory assets Deferred energy and fuel cost adjustments - current (a) (d) 1 $ 23,473 $ 17,491 $ 24,479 Deferred gas cost adjustments (a)(d) 1 8,991 15,329 14,895 Gas price derivatives (a) 4 11,520 8,843 20,324 Deferred taxes on AFUDC (b) 45 14,976 15,227 13,677 Employee benefit plans (c) 12 109,172 108,556 111,661 Environmental (a) subject to approval 1,089 1,108 1,162 Asset retirement obligations (a) 44 507 505 487 Loss on reacquired debt (a) 30 19,869 20,188 3,097 Renewable energy standard adjustment (b) 5 1,138 1,605 4,507 Deferred taxes on flow through accounting (c) 35 39,152 37,498 30,614 Decommissioning costs (e) 10 15,745 16,859 18,134 Gas supply contract termination 5 24,178 26,666 30,613 Other regulatory assets (a) 15 32,779 26,267 19,481 $ 302,589 $ 296,142 $ 293,131 Regulatory liabilities Deferred energy and gas costs (a) (d) 1 $ 21,507 $ 10,368 $ 40,797 Employee benefit plans (c) 12 67,973 68,654 63,580 Cost of removal (a) 44 122,197 118,410 123,076 Revenue subject to refund 1 1,345 2,485 1,131 Other regulatory liabilities (c) 25 5,634 6,839 7,686 $ 218,656 $ 206,756 $ 236,270 __________ (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) South Dakota Electric has approximately $12 million of decommissioning costs associated with the retirements of the Neil Simpson I and Ben French power plants for which we are allowed a rate of return, in addition to recovery of costs.

Materials, Supplies and Fuel_ (

Materials, Supplies and Fuel: (Tables)	3 Months Ended
	Mar. 31, 2017
Inventory, Net [Abstract]
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Materials and supplies $ 71,823 $ 68,456 $ 66,542 Fuel - Electric Utilities 3,433 3,667 5,365 Natural gas in storage held for distribution 9,228 35,087 6,269 Total materials, supplies and fuel $ 84,484 $ 107,210 $ 78,176

Earnings Per Share_ (Tables)

Earnings Per Share: (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands): Three Months Ended March 31, 2017 2016 Net income (loss) available for common stock $ 76,523 $ 40,002 Weighted average shares - basic 53,152 51,044 Dilutive effect of: Equity Units (a) 1,595 720 Equity compensation 185 94 Weighted average shares - diluted 54,932 51,858 __________ (a) Calculated using the treasury stock method.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following outstanding securities were excluded in the computation of diluted net income (loss) per share as their inclusion would have been anti-dilutive (in thousands): Three Months Ended March 31, 2017 2016 Equity compensation — 74 Anti-dilutive shares — 74

Notes Payable_ (Tables)

Notes Payable: (Tables)	3 Months Ended
	Mar. 31, 2017
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: March 31, 2017 December 31, 2016 March 31, 2016 Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Balance Outstanding Letters of Credit Revolving Credit Facility $ — $ 28,100 $ 96,600 $ 36,000 $ 215,600 $ 24,000 CP Program 50,950 — — — — — Total $ 50,950 $ 28,100 $ 96,600 $ 36,000 $ 215,600 $ 24,000
Schedule of Credit Facility Covenants	Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: As of March 31, 2017 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 61% Less than 65%

Equity_ (Tables)

Equity: (Tables)	3 Months Ended
	Mar. 31, 2017
Statement of Stockholders' Equity [Abstract]
Schedule of Stockholders Equity	A summary of the changes in equity is as follows: Three Months Ended March 31, 2017 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2016 $ 1,614,639 $ 115,495 $ 1,730,134 Net income (loss) 76,523 3,516 80,039 Other comprehensive income (loss) 1,153 — 1,153 Dividends on common stock (23,754 ) — (23,754 ) Share-based compensation 2,392 — 2,392 Dividend reinvestment and stock purchase plan 748 — 748 Redeemable noncontrolling interest (1,096 ) — (1,096 ) Cumulative effect of ASU 2016-09 implementation 3,714 — 3,714 Other stock transactions (3 ) — (3 ) Distribution to noncontrolling interest — (4,349 ) (4,349 ) Balance at March 31, 2017 $ 1,674,316 $ 114,662 $ 1,788,978 Three Months Ended March 31, 2016 Total Stockholders’ Equity Noncontrolling Interest Total Equity (in thousands) Balance at December 31, 2015 $ 1,465,867 $ — $ 1,465,867 Net income (loss) 40,002 — 40,002 Other comprehensive income (loss) (11,770 ) — (11,770 ) Dividends on common stock (21,543 ) — (21,543 ) Share-based compensation 561 — 561 Issuance of common stock 6,824 — 6,824 Dividend reinvestment and stock purchase plan 755 — 755 Other stock transactions (13 ) — (13 ) Balance at March 31, 2016 $ 1,480,683 $ — $ 1,480,683
Schedule of Variable Interest Entities	We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of: March 31, 2017 December 31, 2016 March 31, 2016 (in thousands) Assets Current assets $ 12,167 $ 12,627 $ — Property, plant and equipment of variable interest entities, net $ 217,083 $ 218,798 $ — Liabilities Current liabilities $ 3,464 $ 4,342 $ —

Risk Management Activities_ (Ta

Risk Management Activities: (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative [Line Items]
Schedule of Derivative Instruments	The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Designated Designated (a) Designated (b) Designated (b) Designated (a) Notional $ — $ 50,000 $ 150,000 $ 250,000 $ 75,000 Weighted average fixed interest rate — % 4.94 % 2.09 % 2.29 % 4.97 % Maximum terms in months 0 1 13 13 10 Derivative assets, non-current $ — $ — — $ — $ — Derivative liabilities, current $ — $ 90 — $ — $ 2,290 Derivative liabilities, non-current $ — $ — $ 3,785 $ 10,693 $ — __________ (a) The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings . (b) These swaps were settled and terminated in August 2016 in conjunction with the refinancing of acquired SourceGas debt.
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: March 31, 2017 December 31, 2016 March 31, 2016 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 12,330,000 45 14,770,000 48 18,270,000 57 Natural gas options purchased, net 500,000 21 3,020,000 5 990,000 21 Natural gas basis swaps purchased 11,230,000 45 12,250,000 48 16,810,000 57 Natural gas over-the-counter swaps, net (b) 3,165,952 26 4,622,302 28 1,557,011 23 Natural gas physical contracts, net 3,015,234 12 21,504,378 10 2,135,050 12 __________ (a) Term reflects the maximum forward period hedged. (b) 1,180,000 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 is presented below for the three months ended March 31, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. Three Months Ended March 31, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (712 ) Interest expense $ — Commodity derivatives Revenue 229 Revenue — Commodity derivatives Fuel, purchased power and cost of natural gas sold 58 Fuel, purchased power and cost of natural gas sold — Total $ (425 ) $ — Three Months Ended March 31, 2016 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ 1,709 Interest expense $ — Commodity derivatives Revenue 3,592 Revenue $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold 57 Fuel, purchased power and cost of natural gas sold — Total $ 5,358 $ — The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the three months ended March 31 , 2017 and 2016 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income as incurred. Three Months Ended 2017 2016 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ 90 $ (15,047 ) Forward commodity contracts 926 1,827 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 712 (1,709 ) Forward commodity contracts (287 ) (3,649 ) Total other comprehensive income (loss) from hedging $ 1,441 $ (18,578 ) Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three months ended March 31 , 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. Three Months Ended March 31, 2017 2016 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Revenue $ 117 $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (809 ) 634 $ (692 ) $ 634 As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets. The net unrealized losses included in our Regulatory assets related to the hedges in our Utilities were $12 million , $8.8 million and $20 million at March 31, 2017 , December 31, 2016 and March 31, 2016 , respectively.
Oil and Gas
Derivative [Line Items]
Schedule of Derivative Instruments	We had the following short positions as of: March 31, 2017 December 31, 2016 March 31, 2016 Crude Oil Futures Crude Oil Options Natural Gas Futures and Swaps Crude Oil Futures Crude Oil Options Natural Gas Futures and Swaps Crude Oil Futures Natural Gas Futures and Swaps Notional (a) 90,000 27,000 1,890,000 108,000 36,000 2,700,000 159,000 3,447,500 Maximum terms in months (b) 21 9 9 24 12 12 21 21 __________ (a) Crude oil futures and call options in Bbls, natural gas in MMBtus. (b) Term reflects the maximum forward period hedged.

Fair Value Measurements_ (Table

Fair Value Measurements: (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy, Measured on Recurring Basis	The following tables set forth by level within the fair value hierarchy are gross assets and gross liabilities and related offsetting cash collateral and counterparty netting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. As of March 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 1,536 $ — $ (977 ) $ 559 Commodity derivatives — Utilities — 2,642 — (1,651 ) 991 Total $ — $ 4,178 $ — $ (2,628 ) $ 1,550 Liabilities: Commodity derivatives — Oil and Gas $ — $ 434 $ — $ — $ 434 Commodity derivatives — Utilities — 13,139 — (12,933 ) 206 Total $ — $ 13,573 $ — $ (12,933 ) $ 640 As of December 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 2,886 $ — $ (2,733 ) $ 153 Commodity derivatives —Utilities — 7,469 — (3,262 ) 4,207 Interest Rate Swaps — — — — — Total $ — $ 10,355 $ — $ (5,995 ) $ 4,360 Liabilities: Commodity derivatives — Oil and Gas $ — $ 1,586 $ — $ — $ 1,586 Commodity derivatives — Utilities — 12,201 — (11,144 ) 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 13,877 $ — $ (11,144 ) $ 2,733 As of March 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total (in thousands) Assets: Commodity derivatives — Oil and Gas $ — $ 8,429 $ — $ (8,429 ) $ — Commodity derivatives — Utilities — 3,070 — (1,499 ) 1,571 Total $ — $ 11,499 $ — $ (9,928 ) $ 1,571 Liabilities: Commodity derivatives — Oil and Gas $ — $ 251 $ — $ (251 ) $ — Commodity derivatives — Utilities — 23,428 — (21,709 ) 1,719 Interest rate swaps — 16,768 — — 16,768 Total $ — $ 40,447 $ — $ (21,960 ) $ 18,487
Schedule of Derivative Instruments Balance Sheet Location	The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands): As of March 31, 2017 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 722 $ — Commodity derivatives Derivative liabilities — current — 305 Commodity derivatives Derivative liabilities — non-current — 71 Total derivatives designated as hedges $ 722 $ 376 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 819 $ — Commodity derivatives Derivative assets — non-current 9 — Commodity derivatives Derivative liabilities — current — 159 Commodity derivatives Derivative liabilities — non-current — 105 Total derivatives not designated as hedges $ 828 $ 264 As of December 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 1,161 $ — Commodity derivatives Derivative assets — non-current 124 — Commodity derivatives Derivative liabilities — current — 1,090 Commodity derivatives Derivative liabilities — non-current — 238 Interest rate swaps Derivative liabilities — current — 90 Total derivatives designated as hedges $ 1,285 $ 1,418 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 2,977 $ — Commodity derivatives Derivative assets — non-current 98 — Commodity derivatives Derivative liabilities — current — 1,279 Commodity derivatives Derivative liabilities — non-current — 36 Total derivatives not designated as hedges $ 3,075 $ 1,315 As of March 31, 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets — current $ 159 $ — Commodity derivatives Derivative assets — non-current 6 — Commodity derivatives Derivative liabilities — current — 770 Commodity derivatives Derivative liabilities — non-current — 33 Interest rate swaps Derivative liabilities — current — 2,290 Interest rate swaps Derivative liabilities — non-current — 14,478 Total derivatives designated as hedges $ 165 $ 17,571 Derivatives not designated as hedges: Commodity derivatives Derivative assets — current $ 1,327 $ — Commodity derivatives Derivative assets — non-current 79 — Commodity derivatives Derivative liabilities — current — 905 Commodity derivatives Derivative liabilities — non-current — 11 Total derivatives not designated as hedges $ 1,406 $ 916

Fair Value of Financial Instr38

Fair Value of Financial Instruments: (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 11 , were as follows (in thousands) as of: March 31, 2017 December 31, 2016 March 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 11,353 $ 11,353 $ 13,580 $ 13,580 $ 26,046 $ 26,046 Restricted cash and equivalents (a) $ 2,409 $ 2,409 $ 2,274 $ 2,274 $ 1,839 $ 1,839 Notes payable (b) $ 50,950 $ 50,950 $ 96,600 $ 96,600 $ 215,600 $ 215,600 Long-term debt, including current maturities, net of deferred financing costs (c) $ 3,216,473 $ 3,388,809 $ 3,216,932 $ 3,351,305 $ 3,159,055 $ 3,392,652 __________ (a) Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings and borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Other Comprehensive Income (L39

Other Comprehensive Income (Loss): (Tables)	3 Months Ended
	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Reclassification Out of Accumulated Other Comprehensive Income (Loss)	The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Condensed Consolidated Statements of Income Amount Reclassified from AOCI Three months ended March 31, 2017 March 31, 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (712 ) $ 1,709 Commodity contracts Revenue 229 3,592 Commodity contracts Fuel, purchased power and cost of natural gas sold 58 57 (425 ) 5,358 Income tax Income tax benefit (expense) 143 (1,946 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (282 ) $ 3,412 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 48 $ 55 Actuarial gain (loss) Operations and maintenance (414 ) (494 ) (366 ) (439 ) Income tax Income tax benefit (expense) 137 153 Total reclassification adjustments related to defined benefit plans, net of tax $ (229 ) $ (286 ) Total reclassifications $ (511 ) $ 3,126
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within AOCI, net of tax on the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications 58 584 — 642 Amounts reclassified from AOCI 463 (181 ) 229 511 Ending Balance March 31, 2017 $ (17,588 ) $ 170 $ (16,312 ) $ (33,730 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total Balance as of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (9,796 ) 1,152 — (8,644 ) Amounts reclassified from AOCI (1,111 ) (2,301 ) 286 (3,126 ) Ending Balance March 31, 2016 $ (11,248 ) $ 5,917 $ (15,494 ) $ (20,825 )

Supplemental Disclosure of Ca40

Supplemental Disclosure of Cash Flow Information: (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Three Months Ended March 31, 2017 March 31, 2016 (in thousands) Non-cash investing and financing activities— Property, plant and equipment acquired with accrued liabilities $ 28,358 $ 30,260 Cash (paid) refunded during the period — Interest (net of amounts capitalized) $ (36,362 ) $ (15,528 ) Income taxes, net $ 13 $ —

Employee Benefit Plans_ (Tables

Employee Benefit Plans: (Tables)	3 Months Ended
	Mar. 31, 2017
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Net Benefit Costs	The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 2,005 $ 2,078 Interest cost 3,880 3,936 Expected return on plan assets (6,129 ) (5,765 ) Prior service cost 14 15 Net loss (gain) 1,002 1,793 Net periodic benefit cost $ 772 $ 2,057 Defined Benefit Postretirement Healthcare Plans The components of net periodic benefit cost for the Defined Benefit Postretirement Healthcare Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 603 $ 467 Interest cost 533 485 Expected return on plan assets (79 ) (70 ) Prior service cost (benefit) (109 ) (107 ) Net loss (gain) 125 84 Net periodic benefit cost $ 1,073 $ 859 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands): Three Months Ended March 31, 2017 2016 Service cost $ 827 $ 29 Interest cost 319 314 Prior service cost 1 — Net loss (gain) 250 207 Net periodic benefit cost $ 1,397 $ 550
Schedule of Defined Benefit Plans Contributions	Contributions made in 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands): Contributions Made Additional Contributions Contributions Three Months Ended March 31, 2017 Anticipated for 2017 Anticipated for 2018 Defined Benefit Pension Plans $ — $ 10,200 $ 10,200 Non-pension Defined Benefit Postretirement Healthcare Plans $ 1,270 $ 3,811 $ 5,115 Supplemental Non-qualified Defined Benefit and Defined Contribution Plans $ 396 $ 1,187 $ 1,682

Income Taxes_ (Tables)

Income Taxes: (Tables)	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	The effective tax rate differs from the federal statutory rate as follows: Three Months Ended March 31, Tax (benefit) expense 2017 2016 Federal statutory rate 35.0 % 35.0 % State income tax (net of federal tax effect) (a) 1.3 2.6 Percentage depletion in excess of cost (b) (0.4 ) (14.1 ) Accounting for uncertain tax positions adjustment (c) — (11.4 ) Noncontrolling interest (d) (1.1 ) — IRC 172(f) carryback claim (e) (1.8 ) — Tax Credits (f) (1.2 ) — Effective tax rate adjustment (g) (2.4 ) (4.0 ) Transaction costs — 2.5 Other tax differences — (1.0 ) 29.4 % 9.6 % __________ (a) The state income tax benefit is primarily attributable to favorable flow-through adjustments. (b) The tax benefit for the three months ended March 31, 2016 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. (c) The tax benefit for the three months ended March 31, 2016 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. (d) Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9 percent of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision is not recorded. (e) In Q1 2017, the Company filed amended income tax returns for the years 2006 through 2008 to carryback specified liability losses in accordance with IRC172(f). As a result of filing the amended returns, the Company's accrued tax liability interest decreased, certain valuation allowances increased and the previously recorded domestic production activities deduction decreased. (f) The tax credits for the three months ended March 31, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. Peak View began generating production tax credits during the fourth quarter of 2016. (g) Adjustment to reflect our projected annual effective tax rate, pursuant to ASC 740-270.

Accrued Liabilities_ (Tables)

Accrued Liabilities: (Tables)	3 Months Ended
	Mar. 31, 2017
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: March 31, 2017 December 31, 2016 March 31, 2016 (b) Accrued employee compensation, benefits and withholdings $ 47,361 $ 56,926 $ 50,345 Accrued property taxes 41,675 40,004 40,638 Gas-gathering contract (a) — — 39,944 Customer deposits and prepayments 39,288 51,628 42,573 Accrued interest and contract adjustment payments 30,488 45,503 33,381 CIAC current portion 1,575 — 20,466 Other (none of which is individually significant) 43,080 49,973 44,834 Total accrued liabilities $ 203,467 $ 244,034 $ 272,181 _________ (a) This contract was settled on April 29, 2016. (b) To conform with the March 31, 2017 and December 31, 2016 presentation of accrued liabilities, the accrued employee compensation, benefits and withholdings, customer deposits and prepayments, accrued interest and contract adjustment payments and other line items presented above have been reclassified within the disclosure. These changes had no effect on total accrued liabilities.

Management's Statement_ Revisio

Management's Statement: Revisions (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Net Cash Provided By Operating Activities
Prior Period Reclassification Adjustment	$ (5.3)
Cash and Cash Equivalents
Prior Period Reclassification Adjustment	(21)
Accounts Payable
Prior Period Reclassification Adjustment	$ (21)

Management's Statement_ Improve

Management's Statement: Improvements To Employee Share-Based Payment Accounting (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Adjustments for New Accounting Pronouncement
Retained Earnings Adjustments [Line Items]
Cumulative Effect on Retained Earnings, Net of Tax	$ 3.2

Acquisition_ (Details)

Acquisition: (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 12, 2016	Mar. 31, 2017	Mar. 31, 2016
Acquisition Narrative [Abstract]
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired		$ 0	$ 1,132,318
Source Gas
Acquisition Narrative [Abstract]
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired	$ 1,100,000
Long-term debt assumed	$ 760,000
Business Acquisition, Pro Forma Information [Abstract]
Pro Forma - Revenue			528,921
Pro Forma - Net income (loss) available for common stock			$ 66,690
Pro Forma - Earnings per share, Basic (usd per share)			$ 1.31
Pro Forma - Earnings per share, Diluted (usd per share)			$ 1.29
Business Combination, Acquisition Related Costs			$ 16,000

Acquisition_ Noncontrolling Int

Acquisition: Noncontrolling Interest (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Noncontrolling Interest [Abstract]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	0.50%
Payments for Repurchase of Redeemable Noncontrolling Interest	$ 5.6

Business Segment Information_ I

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information
Revenue	$ 554,003	$ 449,959
Net income (loss) available for common stock	76,523	40,002
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	3,623	48
Net tax benefit	3,200	4,400
Tax benefit recognized from Carryback claims for specified liability losses involving prior tax years	1,400
Tax benefit due to the adjustment of the projected annual effective tax rate	1,800
Inter-company eliminations
Segment Reporting Information
Revenue	(33,519)	(35,755)
Net income (loss) available for common stock	0	0
Corporate
Segment Reporting Information
Revenue	0	0
Net income (loss) available for common stock	1,814	(15,636)
Corporate | Incremental, Non-Recurring Acquisition Costs (Net of Tax)
Segment Reporting Information
Business Combination, Acquisition Related Costs	900	15,000
Corporate | Labor (Net Of Tax)
Segment Reporting Information
Business Combination, Acquisition Related Costs	300	3,800
Consolidation, Eliminations
Segment Reporting Information
Revenue	0	0
Electric Utilities
Segment Reporting Information
Revenue	172,170	163,531
Net income (loss) available for common stock	22,230	19,215
Electric Utilities | Inter-company eliminations
Segment Reporting Information
Revenue	3,854	3,745
Gas Utilities
Segment Reporting Information
Revenue	364,901	268,667
Net income (loss) available for common stock	46,010	31,927
Gas Utilities | Inter-company eliminations
Segment Reporting Information
Revenue	9	1,806
Power Generation
Segment Reporting Information
Revenue	2,102	1,852
Net income (loss) available for common stock	6,530	8,582
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	(3,500)
Power Generation | Inter-company eliminations
Segment Reporting Information
Revenue	21,465	21,456
Mining
Segment Reporting Information
Revenue	8,355	7,534
Net income (loss) available for common stock	2,890	2,938
Mining | Inter-company eliminations
Segment Reporting Information
Revenue	8,191	8,748
Oil and Gas
Segment Reporting Information
Revenue	6,475	8,375
Net income (loss) available for common stock	(2,951)	(7,024)
Impairment of Oil and Gas Properties Net of Tax		8,800
Oil and Gas | Inter-company eliminations
Segment Reporting Information
Revenue	$ 0	$ 0

Business Segment Information_ S

Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 6,475,849	$ 6,303,725	$ 6,515,444
Impairment of long-lived assets	0	14,496
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	109,146	112,482	110,691
Electric Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	2,872,989	2,703,774	2,859,559
Gas Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	3,260,989	3,141,897	3,307,967
Power Generation
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	72,540	74,403	73,445
Mining
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	64,973	73,878	67,347
Oil and Gas
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 95,212	197,291	96,435
Impairment of long-lived assets		$ 14,000	$ 107,000

Accounts Receivable_ (Details)

Accounts Receivable: (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (4,298)	$ (2,392)	$ (5,148)
Accounts receivable, net	224,714	263,289	206,276
Corporate
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,100	2,228	2,421
Electric Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(639)	(353)	(772)
Accounts receivable, net	69,818	77,840	73,869
Gas Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(3,646)	(2,026)	(4,363)
Accounts receivable, net	146,307	174,471	123,910
Power Generation
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,353	1,420	1,210
Mining
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	3,197	3,352	2,484
Oil and Gas
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(13)	(13)
Accounts receivable, net	2,939	3,978	2,382
Billed Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	146,308	140,889	123,750
Billed Revenues | Corporate
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,100	2,228	2,421
Billed Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	39,679	41,730	41,981
Billed Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	98,027	88,168	73,259
Billed Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,353	1,420	1,210
Billed Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,197	3,352	2,484
Billed Revenues | Oil and Gas
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,952	3,991	2,395
Unbilled Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	82,704	124,792	87,674
Unbilled Revenues | Corporate
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0	0
Unbilled Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	30,778	36,463	32,660
Unbilled Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	51,926	88,329	55,014
Unbilled Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0	0
Unbilled Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0	0
Unbilled Revenues | Oil and Gas
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 0	$ 0	$ 0

Regulatory Accounting_ (Details

Regulatory Accounting: (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 302,589	$ 296,142	$ 293,131
Regulatory Liabilities	$ 218,656	206,756	236,270
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	1 year
Regulatory Liabilities	$ 21,507	10,368	40,797
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	12 years
Regulatory Liabilities	$ 67,973	68,654	63,580
Cost of removal
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	44 years
Regulatory Liabilities	$ 122,197	118,410	123,076
Revenue Subject to Refund
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	1 year
Regulatory Liabilities	$ 1,345	2,485	1,131
Other regulatory liabilities
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	25 years
Regulatory Liabilities	$ 5,634	6,839	7,686
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	1 year
Regulatory Assets	$ 23,473	17,491	24,479
Deferred gas cost adjustments
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	1 year
Regulatory Assets	$ 8,991	15,329	14,895
Gas price derivatives
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	4 years
Regulatory Assets	$ 11,520	8,843	20,324
AFUDC
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	45 years
Regulatory Assets	$ 14,976	15,227	13,677
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	12 years
Regulatory Assets	$ 109,172	108,556	111,661
Environmental
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 1,089	1,108	1,162
Asset retirement obligations
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	44 years
Regulatory Assets	$ 507	505	487
Loss on reacquired debt
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	30 years
Regulatory Assets	$ 19,869	20,188	3,097
Renewable energy standard adjustment
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	5 years
Regulatory Assets	$ 1,138	1,605	4,507
Flow through accounting
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	35 years
Regulatory Assets	$ 39,152	37,498	30,614
Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	10 years
Regulatory Assets	$ 15,745	16,859	18,134
Gas Supply Contract Termination
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	5 years
Regulatory Assets	$ 24,178	26,666	30,613
Other regulatory assets
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	15 years
Regulatory Assets	$ 32,779	$ 26,267	$ 19,481
South Dakota Electric | Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 12,000

Materials, Supplies and Fuel_52

Materials, Supplies and Fuel: (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Inventory, Net [Abstract]
Materials and supplies	$ 71,823	$ 68,456	$ 66,542
Fuel - Electric Utilities	3,433	3,667	5,365
Natural gas in storage held for distribution	9,228	35,087	6,269
Total materials, supplies and fuel	$ 84,484	$ 107,210	$ 78,176

Earnings Per Share_ Earnings Pe

Earnings Per Share: Earnings Per Share Reconciliation (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income (loss) available for common stock	$ 76,523	$ 40,002
Weighted average shares - basic	53,152	51,044
Dilutive effect of:
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	1,595	720
Equity compensation	185	94
Weighted average shares - diluted	54,932	51,858

Earnings Per Share_ Anti-diluti

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0	74
Stock Compensation Plan
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0	74

Notes Payable_ Schedule of Shor

Notes Payable: Schedule of Short-term Debt and Narrative (Details)	Aug. 09, 2016USD ($)crecit_extension	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 22, 2016USD ($)	Aug. 08, 2016USD ($)	Mar. 31, 2016USD ($)
Short-term Debt [Line Items]
Notes payable		$ 50,950,000	$ 96,600,000			$ 215,600,000
Letters of Credit		28,100,000	36,000,000			24,000,000
Commercial Paper, Maximum Borrowing Capacity		750,000,000		$ 750,000,000
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable		0	96,600,000			215,600,000
Letters of Credit		28,100,000	36,000,000			24,000,000
Line of Credit Facility, Current Borrowing Capacity	$ 750,000,000				$ 500,000,000
Number Of One-Year Extension Options | crecit_extension	2
Debt Instrument, Term	1 year
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,000,000,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.20%
Revolving Credit Facility | Base Rate
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		0.25%
Revolving Credit Facility | Eurodollar
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.25%
Revolving Credit Facility | Letter of Credit
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.25%
Commercial Paper
Short-term Debt [Line Items]
Notes payable		$ 50,950,000	$ 0			$ 0
Debt Instrument, Term		397 days
Short-term Debt, Weighted Average Interest Rate		1.27%

Notes Payable_ Debt covenants (

Notes Payable: Debt covenants (Details)	Mar. 31, 2017
Revolving Credit Facility
Recourse Leverage Ratio	61.00%
Debt instrument, covenant, Leverage Recourse Ratio	0.65
Maximum
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year	0.65

Equity_ Stockholders Equity Rec

Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Stockholders' Equity, beginning balance	$ 1,614,639
Noncontrolling Interest, beginning balance	115,495
Total Equity, beginning balance	1,730,134	$ 1,465,867
Net income (loss) available for common stock	76,523	40,002
Net Income (Loss) Attributable to Noncontrolling Interest	3,623	48
Net Income (Loss) Including Portion Attributable to Noncontrolling Interest (Excluding Income Loss Attributable to Redeemable Noncontrolling Interest)	80,039	40,002
Other comprehensive income (loss)	1,153	(11,770)
Dividends on common stock	(23,754)	(21,543)
Share-based compensation	2,392	561
Issuance of common stock		6,824
Dividend reinvestment and stock purchase plan	748	755
Redeemable noncontrolling interest	(1,096)
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	3,714
Other stock transactions	(3)	(13)
Distribution to noncontrolling interest	(4,349)
Total Stockholders' Equity, ending balance	1,674,316	1,480,683
Noncontrolling Interest, ending balance	114,662	0
Total Equity, ending balance	1,788,978	1,480,683
Parent
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Total Stockholders' Equity, beginning balance	1,614,639	1,465,867
Net income (loss) available for common stock	76,523	40,002
Other comprehensive income (loss)	1,153	(11,770)
Dividends on common stock	(23,754)	(21,543)
Share-based compensation	2,392	561
Issuance of common stock		6,824
Dividend reinvestment and stock purchase plan	748	755
Redeemable noncontrolling interest	(1,096)
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	3,714
Other stock transactions	(3)	(13)
Distribution to noncontrolling interest	0
Total Stockholders' Equity, ending balance	1,674,316	1,480,683
Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling Interest, beginning balance	115,495	0
Net Income (Loss) Attributable to Noncontrolling Interest	3,516	0
Other comprehensive income (loss)	0	0
Dividends on common stock	0	0
Share-based compensation	0	0
Issuance of common stock		0
Dividend reinvestment and stock purchase plan	0	0
Redeemable noncontrolling interest	0
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net	0
Other stock transactions	0	0
Distribution to noncontrolling interest	(4,349)
Noncontrolling Interest, ending balance	$ 114,662	$ 0

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 18, 2016
At The Market Equity Offering Program Authorized Aggregate Value		$ 200
Payments of Stock Issuance Costs	$ 0.1
Common Stock
At The Market Equity Offering Program Shares Issued	121,000
At the Market Equity Program - Proceeds From Sale of Stock	$ 7

Equity_ Variable Interest Entit

Equity: Variable Interest Entities (Details) $ in Thousands	Apr. 14, 2016USD ($)	Mar. 31, 2016USD ($)MW	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage		49.90%
Current assets		$ 402,218	$ 401,402	$ 466,814
Property, plant and equipment of variable interest entities, net		6,063,943	6,436,610	6,412,223
Current liabilities		$ 639,334	391,542	527,932
Variable Interest Entity, Primary Beneficiary
Electric Generation Capacity, Megawatts | MW		200
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Sale of noncontrolling interest	$ 216,000
Current assets		$ 0	12,167	12,627
Property, plant and equipment of variable interest entities, net		0	217,083	218,798
Current liabilities		$ 0	$ 3,464	$ 4,342

Risk Management Activities_ Oil

Risk Management Activities: Oil and Gas (Details) - Oil and Gas $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)MMBTUbbl	Mar. 31, 2016MMBTUbbl	Dec. 31, 2016MMBTUbbl
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 0.3
Swaps and Options | Crude Oil
Derivative [Line Items]
Notional amount - commodities	90,000	159,000	108,000
Maximum Term Hedged in Cash Flow Hedge	21 months	21 months	24 months
Options Held | Crude Oil
Derivative [Line Items]
Notional amount - commodities	27,000		36,000
Maximum Term Hedged in Cash Flow Hedge	9 months		12 months
Swap | Natural Gas
Derivative [Line Items]
Notional amount - commodities | MMBTU	1,890,000	3,447,500	2,700,000
Maximum Term Hedged in Cash Flow Hedge	9 months	21 months	12 months

Risk Management Activities_ Uti

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution - MMBTU	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Cash Flow Hedging
Derivative [Line Items]
Notional amount - commodities	1,180,000
Future
Derivative [Line Items]
Notional amount - commodities	12,330,000	18,270,000	14,770,000
Maximum Term	45 months	57 months	48 months
Commodity Option
Derivative [Line Items]
Notional amount - commodities	500,000	990,000	3,020,000
Maximum Term	21 months	21 months	5 months
Basis Swap
Derivative [Line Items]
Notional amount - commodities	11,230,000	16,810,000	12,250,000
Maximum Term	45 months	57 months	48 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Notional amount - commodities	3,165,952	1,557,011	4,622,302
Maximum Term	26 months	23 months	28 months
Natural Gas Physical Purchases
Derivative [Line Items]
Notional amount - commodities	3,015,234	2,135,050	21,504,378
Maximum Term	12 months	12 months	10 months

Risk Management Activities_ Fin

Risk Management Activities: Financing Activities (Details) - USD ($) $ in Thousands	Aug. 19, 2016	Aug. 10, 2016	Aug. 09, 2016	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Jan. 31, 2016
Derivative [Line Items]
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion				$ 28,000
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)				1,000
Derivative assets, non-current				9	$ 85	$ 222
Derivative liabilities, current				464	3,965	2,459
Derivative liabilities, non-current				176	14,522	274
Revolving Credit Facility
Derivative [Line Items]
Debt Instrument, Term			1 year
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2027
Derivative [Line Items]
Long-term Debt, Gross	$ 400,000	$ 400,000
Debt Instrument, Term	10 years	10 years
Interest Rate Swap
Derivative [Line Items]
Notional Amount							$ 400,000
Interest rate swap settlement		$ 29,000
Interest Rate Swap | Designated as Hedging Instrument
Derivative [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net				(2,900)
Interest Rate Swap | Designated as Hedging Instrument | Interest Rate Swap One
Derivative [Line Items]
Notional Amount					$ 250,000
Weighted average fixed interest rate					2.29%
Maximum Term					13 months
Derivative assets, non-current					$ 0
Derivative liabilities, current					0
Derivative liabilities, non-current					10,693
Interest Rate Swap | Designated as Hedging Instrument | Revolving Credit Facility
Derivative [Line Items]
Notional Amount				$ 0		$ 50,000
Weighted average fixed interest rate				0.00%		4.94%
Maximum Term				0 months		1 month
Derivative assets, non-current				$ 0		$ 0
Derivative liabilities, current				0		90
Derivative liabilities, non-current				0		0
Derivative Expired During the Period				$ 50,000		$ 25,000
Interest Rate Swap | Designated as Hedging Instrument | Revolving Credit Facility | Interest Rate Swap Two
Derivative [Line Items]
Notional Amount					$ 75,000
Weighted average fixed interest rate					4.97%
Maximum Term					10 months
Derivative assets, non-current					$ 0
Derivative liabilities, current					2,290
Derivative liabilities, non-current					0
Interest Rate Swap | Designated as Hedging Instrument | Revolving Credit Facility | Interest Rate Swap Three
Derivative [Line Items]
Notional Amount					$ 150,000
Weighted average fixed interest rate					2.09%
Maximum Term					13 months
Derivative assets, non-current					$ 0
Derivative liabilities, current					0
Derivative liabilities, non-current					$ 3,785

Risk Management Activities_ Hed

Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 1,000
Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	$ 0
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(425)	5,358
Cash Flow Hedging | Interest Rate Swap | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(712)	1,709
Cash Flow Hedging | Commodity Contract | Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	229	3,592
Cash Flow Hedging | Commodity Contract | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	58	57
Designated as Hedging Instrument | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,441	(18,578)
Designated as Hedging Instrument | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	90	(15,047)
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	712	(1,709)
Designated as Hedging Instrument | Cash Flow Hedging | Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	926	1,827
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	$ (287)	$ (3,649)

Risk Management Activities_ Der

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Regulatory Assets	$ 302,589	$ 293,131	$ 296,142
Price Risk Derivative
Regulatory Assets	11,520	20,324	$ 8,843
Not Designated as Hedging Instrument
Derivative, Gain (Loss) on Derivative, Net	(692)	634
Not Designated as Hedging Instrument | Sales Revenue, Net
Derivative, Gain (Loss) on Derivative, Net	117	0
Not Designated as Hedging Instrument | Cost of Sales
Derivative, Gain (Loss) on Derivative, Net	$ (809)	$ 634

Fair Value Measurements_ Schedu

Fair Value Measurements: Schedule of Fair Values (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	$ (2,628)	$ (5,995)	$ (9,928)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(12,933)	(11,144)	(21,960)
Interest Rate Swap
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
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0	0
Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,651)	(3,262)	(1,499)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(12,933)	(11,144)	(21,709)
Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(977)	(2,733)	(8,429)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	(251)
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 1 | Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives		0
Derivative Liabilities, Fair Value Disclosure		0	0
Fair Value, Inputs, Level 1 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Fair Value, Inputs, Level 1 | Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	4,178	10,355	11,499
Derivative Liabilities, Total	13,573	13,877	40,447
Fair Value, Inputs, Level 2 | Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives		0
Derivative Liabilities, Fair Value Disclosure		90	16,768
Fair Value, Inputs, Level 2 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	2,642	7,469	3,070
Derivative Liabilities, Fair Value Disclosure	13,139	12,201	23,428
Fair Value, Inputs, Level 2 | Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	1,536	2,886	8,429
Derivative Liabilities, Fair Value Disclosure	434	1,586	251
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0	0
Derivative Liabilities, Total	0	0	0
Fair Value, Inputs, Level 3 | Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives		0
Derivative Liabilities, Fair Value Disclosure		0	0
Fair Value, Inputs, Level 3 | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0	0
Derivative Liabilities, Fair Value Disclosure	0	0	0
Fair Value, Inputs, Level 3 | Oil and Gas
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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	1,550	4,360	1,571
Derivative Liabilities, Total	640	2,733	18,487
Estimate of Fair Value Measurement | Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives		0
Derivative Liabilities, Fair Value Disclosure		90	16,768
Estimate of Fair Value Measurement | Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	991	4,207	1,571
Derivative Liabilities, Fair Value Disclosure	206	1,057	1,719
Estimate of Fair Value Measurement | Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	559	153	0
Derivative Liabilities, Fair Value Disclosure	$ 434	$ 1,586	$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 722	$ 1,285	$ 165
Derivative Liability, Fair Value, Net	376	1,418	17,571
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	828	3,075	1,406
Derivative Liability, Fair Value, Net	264	1,315	916
Commodity Contract | Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	722	1,161	159
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract | Designated as Hedging Instrument | Derivative Assets, Non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		124	6
Derivative Asset, Fair Value, Gross Liability		0	0
Commodity Contract | Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	305	1,090	770
Commodity Contract | Designated as Hedging Instrument | Derivative Liabilities, Non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	71	238	33
Commodity Contract | Not Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	819	2,977	1,327
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract | Not Designated as Hedging Instrument | Derivative Assets, Non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	9	98	79
Derivative Asset, Fair Value, Gross Liability	0	0	0
Commodity Contract | Not Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	159	1,279	905
Commodity Contract | Not Designated as Hedging Instrument | Derivative Liabilities, Non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0	0
Derivative Liability, Fair Value, Gross Liability	$ 105	36	11
Interest Rate Swap | Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset		0	0
Derivative Liability, Fair Value, Gross Liability		$ 90	2,290
Interest Rate Swap | Designated as Hedging Instrument | Derivative Liabilities, Non-current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset			0
Derivative Liability, Fair Value, Gross Liability			$ 14,478

Fair Value of Financial Instr67

Fair Value of Financial Instruments: (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 11,353	$ 13,580	$ 26,046	$ 440,861
Restricted cash and equivalents	2,409	2,274	1,839
Notes payable	50,950	96,600	215,600
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	11,353	13,580	26,046
Restricted cash and equivalents	2,409	2,274	1,839
Notes payable	50,950	96,600	215,600
Long-term debt, including current maturities	3,216,473	3,216,932	3,159,055
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	11,353	13,580	26,046
Restricted Cash Fair Value Disclosure	2,409	2,274	1,839
Notes payable, Fair Value	50,950	96,600	215,600
Long-term debt, including current maturities, Fair Value	$ 3,388,809	$ 3,351,305	$ 3,392,652

Other Comprehensive Income (L68

Other Comprehensive Income (Loss): Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 35,096	$ 32,074
Revenue	554,003	449,959
Fuel, purchased power and cost of natural gas sold	219,777	171,856
Operations and maintenance	122,130	107,062
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	113,501	44,302
Income tax benefit (expense)	(33,355)	(4,252)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	80,146	40,050
Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(511)	3,126
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(425)	5,358
Income tax benefit (expense)	143	(1,946)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(282)	3,412
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification Out Of Accumulated Other Comprehensive Income | Interest Rate Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(712)	1,709
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification Out Of Accumulated Other Comprehensive Income | Commodity Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Revenue	229	3,592
Fuel, purchased power and cost of natural gas sold	58	57
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) | Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	48	55
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	(414)	(494)
Accumulated Defined Benefit Plans Adjustment | Reclassification Out Of Accumulated Other Comprehensive Income
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(366)	(439)
Income tax benefit (expense)	137	153
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (229)	$ (286)

Other Comprehensive Income (L69

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (34,883)	$ (9,055)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(33,730)	(20,825)
Accumulated Defined Benefit Plans Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(16,541)	(15,780)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(16,312)	(15,494)
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	642	(8,644)
Interest Rate Swap | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(18,109)	(341)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	58	(9,796)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(17,588)	(11,248)
Commodity Contract | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(233)	7,066
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	584	1,152
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	170	5,917
Reclassification Out Of Accumulated Other Comprehensive Income | Accumulated Defined Benefit Plans Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	229	286
Reclassification Out Of Accumulated Other Comprehensive Income | AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	511	(3,126)
Reclassification Out Of Accumulated Other Comprehensive Income | Interest Rate Swap | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	463	(1,111)
Reclassification Out Of Accumulated Other Comprehensive Income | Commodity Contract | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ (181)	$ (2,301)

Supplemental Disclosure of Ca70

Supplemental Disclosure of Cash Flow Information: (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 28,358	$ 30,260
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(36,362)	(15,528)
Income taxes, net	$ 13	$ 0

Employee Benefit Plans_ (Detail

Employee Benefit Plans: (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 2,005	$ 2,078
Interest Cost	3,880	3,936
Expected return on plan assets	(6,129)	(5,765)
Prior service cost (benefit)	14	15
Net loss (gain)	1,002	1,793
Net periodic benefit cost	772	2,057
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	0
Estimated Future Employer Contributions in Current Fiscal Year	10,200
Estimated Future Employer Contributions in Next Fiscal Year	10,200
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	827	29
Interest Cost	319	314
Prior service cost (benefit)	1	0
Net loss (gain)	250	207
Net periodic benefit cost	1,397	550
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	396
Estimated Future Employer Contributions in Current Fiscal Year	1,187
Estimated Future Employer Contributions in Next Fiscal Year	1,682
Other Postretirement Benefit Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	603	467
Interest Cost	533	485
Expected return on plan assets	(79)	(70)
Prior service cost (benefit)	(109)	(107)
Net loss (gain)	125	84
Net periodic benefit cost	1,073	$ 859
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	1,270
Estimated Future Employer Contributions in Current Fiscal Year	3,811
Estimated Future Employer Contributions in Next Fiscal Year	$ 5,115

Commitments and Contingencies_

Commitments and Contingencies: Dividend Restrictions (Details) $ in Millions	Mar. 31, 2017USD ($)
Utilities Group
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Impairment of Assets_ Impairmen

Impairment of Assets: Impairment of Long-lived assets (Details)	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)	Mar. 31, 2017$ / bbl$ / MMcf	Mar. 31, 2016$ / bbl$ / MMcf
Impairment of Oil and Gas Properties | $	$ 0	$ 14,496,000
Oil and Gas
Impairment of Oil and Gas Properties | $	$ 0	$ 14,000,000
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf			2.73	2.40
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf			2.48	1.13
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl			47.61	46.26
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl			42.81	39.80

Income Taxes_ (Details)

Income Taxes: (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
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%
State income tax (net of federal tax effect)	1.30%	2.60%
Percentage depletion in excess of cost	(0.40%)	(14.10%)
Accounting for uncertain tax positions adjustment	0.00%	(11.40%)
Noncontrolling interest	(1.10%)	0.00%
Effective Income Tax Rate Reconciliation, NOL Carryback Specified Liability Loss	(1.80%)	0.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(1.20%)	(0.00%)
Transaction costs	0.00%	2.50%
Inter-period tax allocation	(2.40%)	(4.00%)
Other tax differences	0.00%	(1.00%)
Effective Tax Rate	29.40%	9.60%
IRS Settlement [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		$ 35
Income Tax Examination, Increase (Decrease) In Accrued Interest		$ 5.1
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 8

Accrued Liabilities_ (Details)

Accrued Liabilities: (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 47,361	$ 56,926	$ 50,345
Accrued property taxes	41,675	40,004	40,638
Gas-gathering contract	0	0	39,944
Customer deposits and prepayments	39,288	51,628	42,573
Accrued interest and contract adjustment payments	30,488	45,503	33,381
CIAC current portion	1,575	0	20,466
Other (none of which is individually significant)	43,080	49,973	44,834
Total accrued liabilities	$ 203,467	$ 244,034	$ 272,181