View Filing Data

Print Document View Excel Document

Document and Entity Information Document - shares	6 Months Ended
Document and Entity Information Document - shares	Jun. 30, 2017	Jul. 31, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	0001130464
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,475,190
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Statement [Abstract]
Revenue	$ 347,978	$ 325,441	$ 901,981	$ 775,400
Operating expenses:
Fuel, purchased power and cost of natural gas sold	98,164	84,489	317,941	256,345
Operations and maintenance	117,374	112,541	239,504	219,603
Depreciation, depletion and amortization	48,663	47,305	97,310	91,712
Taxes - property, production and severance	13,743	12,760	27,712	24,877
Impairment of long-lived assets	0	25,497	0	39,993
Other operating expenses	1,168	7,551	3,137	33,982
Total operating expenses	279,112	290,143	685,604	666,512
Operating income	68,866	35,298	216,377	108,888
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(35,098)	(34,609)	(70,194)	(66,683)
Allowance for funds used during construction - borrowed	822	754	1,308	1,255
Capitalized interest	130	268	299	503
Interest income	257	946	298	1,601
Allowance for funds used during construction - equity	794	982	1,286	1,689
Other income (expense), net	(58)	(47)	(160)	641
Total other income (expense), net	(33,153)	(31,706)	(67,163)	(60,994)
Income before income taxes	35,713	3,592	149,214	47,894
Income tax benefit (expense)	(10,402)	(309)	(43,757)	(4,561)
Net income	25,311	3,283	105,457	43,333
Net income attributable to noncontrolling interest	(3,116)	(2,614)	(6,739)	(2,662)
Net income available for common stock	$ 22,195	$ 669	$ 98,718	$ 40,671
Earnings per share of common stock:
Earnings (loss) per share, Basic (usd per share)	$ 0.42	$ 0.01	$ 1.86	$ 0.79
Earnings (loss) per share, Diluted (usd per share)	$ 0.40	$ 0.01	$ 1.79	$ 0.78
Weighted average common shares outstanding:
Basic (in shares)	53,229	51,514	53,191	51,279
Diluted (in shares)	55,384	52,986	55,179	52,454
Dividends declared per share of common stock (usd per share)	$ 0.445	$ 0.420	$ 0.890	$ 0.840

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net income (loss)	$ 25,311	$ 3,283	$ 105,457	$ 43,333
Other comprehensive income (loss), net of tax:
Reclassification adjustments of benefit plan liability - prior service cost	(31)	(36)	(62)	(72)
Reclassification adjustments of benefit plan liability - net gain (loss)	268	321	528	643
Other comprehensive income (loss), net of tax	789	(10,939)	1,942	(22,709)
Comprehensive income (loss)	26,100	(7,656)	107,399	20,624
Less: comprehensive income attributable to noncontrolling interest	(3,116)	(2,614)	(6,739)	(2,662)
Comprehensive income (loss) available for common stock	22,984	(10,270)	100,660	17,962
Interest Rate Swap
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	0	(8,174)	0	(19,898)
Reclassification of net realized (gains) losses	464	546	985	1,098
Commodity Contract
Other comprehensive income (loss), net of tax:
Net unrealized gains (losses)	331	(1,546)	915	(168)
Reclassification of net realized (gains) losses	$ (243)	$ (2,050)	$ (424)	$ (4,312)

Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Reclassification adjustment of benefit plan - prior service cost, (tax) benefit	$ 18	$ 19	$ 35	$ 38
Reclassification adjustment of benefit plan liabilities, (tax) benefit	(146)	(173)	(300)	(346)
Interest Rate Swap
Net unrealized gains/losses, (tax) benefit	0	4,440	0	10,767
Reclassification of net realized gains/losses, (tax) benefit	(249)	(294)	(530)	(592)
Commodity Contract
Net unrealized gains/losses, (tax) benefit	(194)	906	(536)	98
Reclassification of net realized gains/losses, (tax) benefit	$ 143	$ 1,176	$ 249	$ 2,476

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Current assets:
Cash and cash equivalents	$ 11,590	$ 13,580	$ 61,859
Restricted cash and equivalents	2,534	2,274	1,975
Accounts receivable, net	169,957	263,289	150,227
Materials, supplies and fuel	99,126	107,210	85,189
Derivative assets, current	1,148	4,138	4,030
Regulatory assets, current	53,061	49,260	54,856
Other current assets	21,840	27,063	30,652
Total current assets	359,256	466,814	388,788
Investments	12,761	12,561	12,363
Property, plant and equipment	6,533,581	6,412,223	6,209,816
Less: accumulated depreciation and depletion	(1,981,880)	(1,943,234)	(1,819,886)
Total property, plant and equipment, net	4,551,701	4,468,989	4,389,930
Other assets:
Goodwill	1,299,454	1,299,454	1,303,453
Intangible assets, net	7,972	8,392	9,164
Regulatory assets, non-current	244,099	246,882	220,556
Derivative assets, non-current	37	222	226
Other assets, non-current	13,812	12,130	15,438
Total other assets, non-current	1,565,374	1,567,080	1,548,837
TOTAL ASSETS	6,489,092	6,515,444	6,339,918
Current liabilities:
Accounts payable	99,970	153,477	115,203
Accrued liabilities	201,993	244,034	218,250
Derivative liabilities, current	719	2,459	28,855
Accrued income taxes, net	5,160	12,552	10,624
Regulatory liabilities, current	17,305	13,067	34,275
Notes payable	107,975	96,600	75,000
Current maturities of long-term debt	5,743	5,743	930,743
Total current liabilities	438,865	527,932	1,412,950
Long-term debt	3,160,302	3,211,189	2,221,347
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	589,189	535,606	530,746
Derivative liabilities, non-current	88	274	231
Regulatory liabilities, non-current	199,005	193,689	195,166
Benefit plan liabilities	176,102	173,682	173,347
Other deferred credits and other liabilities	135,510	138,643	122,015
Total deferred credits and other liabilities	1,099,894	1,041,894	1,021,505
Commitments and contingencies (See Notes 8, 10, 15, 16)
Redeemable noncontrolling interest	0	4,295	4,171
Equity:
Common stock $1 par value; 100,000,000 shares authorized; issued 53,513,521; 53,397,467; and 52,299,075 shares, respectively	53,514	53,397	52,299
Additional paid-in capital	1,145,493	1,138,982	1,072,927
Retained earnings	512,498	457,934	469,940
Treasury stock, at cost – 39,329; 15,258; and 18,900 shares, respectively	(2,325)	(791)	(975)
Accumulated other comprehensive income (loss)	(32,941)	(34,883)	(31,764)
Total stockholders’ equity	1,676,239	1,614,639	1,562,427
Noncontrolling interest	113,792	115,495	117,518
Total equity	1,790,031	1,730,134	1,679,945
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$ 6,489,092	$ 6,515,444	$ 6,339,918

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - $ / shares	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1	$ 1
Common Stock, Shares Issued	53,513,521	53,397,467	52,299,075
Treasury Stock, Shares	39,329	15,258	18,900
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating activities:
Net income (loss)	$ 105,457	$ 43,333
Net income (loss) available for common stock	98,718	40,671
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	97,310	91,712
Deferred financing cost amortization	4,138	2,857
Impairment of long-lived assets	0	39,993
Stock compensation	6,589	7,054
Deferred income taxes	51,153	32,606
Employee benefit plans	5,717	7,782
Other adjustments, net	(6,515)	(6,332)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	7,720	17,722
Accounts receivable, unbilled revenues and other operating assets	97,902	82,361
Accounts payable and other operating liabilities	(113,541)	(124,695)
Regulatory assets - current	3,086	1,862
Regulatory liabilities - current	5,908	2,994
Pension Contributions	0	(10,200)
Other operating activities, net	(2,055)	(2,884)
Net cash provided by (used in) operating activities	262,869	183,503
Investing activities:
Property, plant and equipment additions	(163,768)	(199,854)
Acquisition, net of long term debt assumed	0	(1,124,238)
Other investing activities	(22)	(649)
Net cash provided by (used in) investing activities	(163,790)	(1,324,741)
Financing activities:
Dividends paid on common stock	(47,544)	(43,265)
Common stock issued	2,965	57,490
Proceeds from Noncontrolling Interests	0	216,370
Net (payments) borrowings of short-term debt	11,375	(1,800)
Long-term debt - issuances	0	574,672
Long-term debt - repayments	(52,871)	(41,436)
Distributions to noncontrolling interest	(8,335)	0
Other financing activities	(6,659)	205
Net cash provided by (used in) financing activities	(101,069)	762,236
Net change in cash and cash equivalents	(1,990)	(379,002)
Cash and cash equivalents, beginning of period	13,580	440,861
Cash and cash equivalents, end of period	$ 11,590	$ 61,859

Management's Statement:	6 Months Ended
Management's Statement:	Jun. 30, 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 June 30, 2017, December 31, 2016, and June 30, 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 and six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017, December 31, 2016, and June 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. June 30, 2017 reflects a full six months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the six months ended June 30, 2016 which reflects a partial period of approximately 4.5 months. 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 as of December 31, 2016. 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 $55 million as of June 30, 2016, and decreased net cash flows provided by operations by $39 million for the six months ended June 30, 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 June 30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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. This ASU 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. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. 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. We will implement this standard effective January 1, 2018. 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). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. 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 a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. 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 currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. 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 revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect 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. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

Acquisition:

6 Months Ended

Jun. 30, 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). We acquired SourceGas for $1.1 billion of cash plus 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 and six months ended June 30, 2016 exclude approximately $4.0 million and $20 million, respectively, of after-tax transaction costs, professional fees, employee related expenses and other miscellaneous costs.



	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
	(in thousands, except per share amounts)
Revenue	$	325,441	$	854,362
Net income (loss) available for common stock	$	4,658	$	72,978
Earnings (loss) per share, Basic	$	0.09	$	1.42
Earnings (loss) per share, Diluted	$	0.09	$	1.39

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.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1524-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4922-128472

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4934-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=73530397&loc=d3e4926-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=65885119&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Business Segment Information:

6 Months Ended

Jun. 30, 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 June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	165,517	$	2,936		$	18,832
Gas	166,439		8			(272		)
Power Generation ^(b)	1,470		20,325			5,332
Mining	8,403		6,543			2,681
Oil and Gas	6,149		—			(1,946		)
Corporate activities ^(c)	—		—			(2,432		)
Inter-company eliminations	—		(29,812		)	—
Total	$	347,978	$	—		$	22,195



Three Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric^.	$	158,560	$	2,921		$	19,229
Gas	153,767		(1,806		)	987
Power Generation ^(b)	1,546		20,168			5,683
Mining	3,922		7,125			724
Oil and Gas ^(e)	7,646		—			(19,424		)
Corporate activities ^(c)	—		—			(6,530		)
Inter-company eliminations	—		(28,408		)	—
Total	$	325,441	$	—		$	669




Six Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	337,687	$	6,790		$	41,062
Gas ^(a)	531,340		17			45,738
Power Generation ^(b)	3,572		41,790			11,862
Mining	16,758		14,734			5,571
Oil and Gas	12,624		—			(4,897		)
Corporate activities ^(c)(d)	—		—			(618		)
Inter-company eliminations	—		(63,331		)	—
Total	$	901,981	$	—		$	98,718




Six Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	322,091	$	6,666		$	38,444
Gas ^(a)	422,434		—			32,914
Power Generation ^(b)	3,398		41,624			14,265
Mining	11,456		15,873			3,662
Oil and Gas ^(e)	16,021		—			(26,448		)
Corporate activities ^(c)(d)	—		—			(22,166		)
Inter-company eliminations	—		(64,163		)	—
Total	$	775,400	$	—		$	40,671

___________


(a)	Gas Utility revenue increased for the six months ended June 30, 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 for the three and six months ended June 30, 2017 was net of net income attributable to noncontrolling interests of $3.1 million and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016.

(c)

Net income (loss) available for common stock for the three and six months ended June 30, 2017 and June 30, 2016 included incremental, non-recurring acquisition costs, net of tax of $0.3 million and $1.2 million, and $4.1 million and $20 million respectively. The three and six months ended June 30, 2016 also included $2.0 million and $5.7 million, respectively, of after-tax internal labor costs attributable to the acquisition.

(d)

Net income (loss) available for common stock for the six months ended June 30, 2017 included a $1.4 million tax benefit recognized from carryback claims for specified liability losses involving prior tax years. Net income (loss) available for common stock for the six months ended June 30, 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 and six months ended June 30, 2016 included non-cash after-tax impairments of oil and gas properties of $16 million and $25 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:	June 30, 2017		December 31, 2016		June 30, 2016
Segment:
Electric ^(a)	$	2,901,570	$	2,859,559	$	2,755,695
Gas	3,242,461		3,307,967		3,118,626
Power Generation ^(a)	66,292		73,445		80,360
Mining	67,365		67,347		71,319
Oil and Gas ^(b)	103,044		96,435		171,239
Corporate activities	108,360		110,691		142,679
Total assets	$	6,489,092	$	6,515,444	$	6,339,918

__________


(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 $40 million for the six months ended June 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Accounts Receivable:

6 Months Ended

Jun. 30, 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
June 30, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,635	$	33,686	$	(466	)	$	74,855
Gas Utilities	62,908		26,584		(2,535		)	86,957
Power Generation	877		—		—			877
Mining	2,904		—		—			2,904
Oil and Gas	3,280		—		(83		)	3,197
Corporate	1,167		—		—			1,167
Total	$	112,771	$	60,270	$	(3,084	)	$	169,957



	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
June 30, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	40,991	$	34,174	$	(716	)	$	74,449
Gas Utilities	47,600		23,124		(2,997		)	67,727
Power Generation	1,229		—		—			1,229
Mining	1,114		—		—			1,114
Oil and Gas	3,094		—		(13		)	3,081
Corporate	2,627		—		—			2,627
Total	$	96,655	$	57,298	$	(3,726	)	$	150,227

- Definition

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

+ References + Details

Regulatory Accounting:

6 Months Ended

Jun. 30, 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	June 30, 2017		December 31, 2016		June 30, 2016
	(in years)
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	20,761	$	17,491	$	20,603
Deferred gas cost adjustments ^(a)(d)	1	9,060		15,329		12,122
Gas price derivatives ^(a)	3.5	11,159		8,843		11,515
Deferred taxes on AFUDC^(b)	45	15,322		15,227		13,879
Employee benefit plans ^(c)	12	107,419		108,556		109,522
Environmental^(a)	subject to approval	1,070		1,108		1,144
Asset retirement obligations^(a)	44	510		505		505
Loss on reacquired debt^(a)	30	21,466		22,266		3,061
Renewable energy standard adjustment ^(b)	5	768		1,605		2,679
Deferred taxes on flow through accounting^(c)	35	40,586		37,498		31,554
Decommissioning costs ^(e)	6	14,681		16,859		18,399
Gas supply contract termination	5	22,793		26,666		28,385
Other regulatory assets^{(a) (e)}	15	31,565		24,189		22,044
		$	297,160	$	296,142	$	275,412

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	16,767	$	10,368	$	32,868
Employee benefit plan costs and related deferred taxes^(c)	12	67,297		68,654		62,712
Cost of removal^(a)	44	125,247		118,410		126,002
Revenue subject to refund	1	1,518		2,485		1,616
Other regulatory liabilities^(c)	25	5,481		6,839		6,243
		$	216,310	$	206,756	$	229,441

__________


(a)	We are allowed 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)

In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately $2.7 million.

Materials, Supplies and Fuel:

6 Months Ended

Jun. 30, 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:



	June 30, 2017		December 31, 2016		June 30, 2016
Materials and supplies	$	72,397	$	68,456	$	67,440
Fuel - Electric Utilities	3,106		3,667		4,659
Natural gas in storage held for distribution	23,623		35,087		13,090
Total materials, supplies and fuel	$	99,126	$	107,210	$	85,189

Earnings Per Share:

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016

Net income (loss) available for common stock	$	22,195	$	669	$	98,718	$	40,671

Weighted average shares - basic	53,229		51,514		53,191		51,279
Dilutive effect of:
Equity Units ^(a)	1,977		1,362		1,796		1,068
Equity compensation	178		110		192		107
Weighted average shares - diluted	55,384		52,986		55,179		52,454

__________


(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 June 30,		Six Months Ended June 30,
	2017	2016	2017	2016

Equity compensation	—	4	—	10
Anti-dilutive shares	—	4	—	10

Notes Payable And Long-term Debt:

6 Months Ended

Jun. 30, 2017

Debt Disclosure [Abstract]

Notes Payable and Long-term Debt

NOTES PAYABLE AND LONG-TERM DEBT

We had the following notes payable outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:



	June 30, 2017				December 31, 2016				June 30, 2016
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700
CP Program	107,975		—		—		—		—		—
Total	$	107,975	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700

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 June 30, 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 six months ended June 30, 2017 and our notes outstanding as of June 30, 2017 were $108 million. As of June 30, 2017, the weighted average interest rate on CP Program borrowings was 1.41%.

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 and 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 June 30, 2017	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	61%	Less than	65%

As of June 30, 2017, we were in compliance with this covenant.

Long-Term Debt

On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan.

Equity:

6 Months Ended

Jun. 30, 2017

Statement of Stockholders' Equity [Abstract]

Equity

EQUITY

A summary of the changes in equity is as follows:



Six Months Ended June 30, 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)	98,718			6,632			105,350
Other comprehensive income (loss)	1,942			—			1,942
Dividends on common stock	(47,544		)	—			(47,544		)
Share-based compensation	4,133			—			4,133
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	1,530			—			1,530
Redeemable noncontrolling interest	(886		)	—			(886		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(7		)	—			(7		)
Distribution to noncontrolling interest	—			(8,335		)	(8,335		)
Balance at June 30, 2017	$	1,676,239		$	113,792		$	1,790,031



Six Months Ended June 30, 2016	Total Stockholders’ Equity			Noncontrolling Interest		Total Equity
				(in thousands)
Balance at December 31, 2015	$	1,465,867		$	—	$	1,465,867
Net income (loss)	40,671			2,632		43,303
Other comprehensive income (loss)	(22,709		)	—		(22,709		)
Dividends on common stock	(43,270		)	—		(43,270		)
Share-based compensation	2,192			—		2,192
Issuance of common stock	55,802			—		55,802
Dividend reinvestment and stock purchase plan	1,478			—		1,478
Other stock transactions	(20		)	—		(20		)
Sale of noncontrolling interest	62,416			114,886		177,302
Balance at June 30, 2016	$	1,562,427		$	117,518	$	1,679,945

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 six months ended June 30, 2017. During the three months ended June 30, 2016, we sold 809,649 common shares for $49 million, net of $0.5 million in commissions, under the ATM equity offering program. During the six months ended June 30, 2016, we sold and issued an aggregate of 930,649 shares of common stock under the ATM equity offering program for $56 million, net of $0.6 million in commissions with settlement dates through June 30, 2016. On August 4, 2017, the Company plans to file for renewal of the ATM equity offering program initiated in 2016 which resets the size of the ATM equity offering program to an aggregate sales price of up to $300 million.

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:



	June 30, 2017		December 31, 2016		June 30, 2016
	(in thousands)
Assets
Current assets	$	12,042	$	12,627	$	12,681
Property, plant and equipment of variable interest entities, net	$	214,239	$	218,798	$	224,128

Liabilities
Current liabilities	$	2,651	$	4,342	$	4,174

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB Topic 4.E)
-URI http://asc.fasb.org/extlink&oid=27010918&loc=d3e74567-122707

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(29))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(e))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(31))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB Topic 4.C)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187143-122770

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(30))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(d))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

+ Details

Risk Management Activities:

6 Months Ended

Jun. 30, 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:



	June 30, 2017			December 31, 2016			June 30, 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)	72,000	18,000	1,080,000	108,000	36,000	2,700,000	210,000	2,530,000
Maximum terms in months ^(b)	18	6	6	24	12	12	30	18

__________


(a)	Crude oil futures and call options in Bbls, natural gas in MMBtus.


(b)	Term reflects the maximum forward period hedged.

Based on June 30, 2017 prices, a $0.5 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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 July 2017 through December 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with 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:



	June 30, 2017		December 31, 2016		June 30, 2016
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	11,060,000	42	14,770,000	48	18,080,000	54
Natural gas options purchased, net	1,640,000	20	3,020,000	5	3,770,000	20
Natural gas basis swaps purchased	10,070,000	42	12,250,000	48	15,320,000	54
Natural gas over-the-counter swaps, net ^(b)	5,200,000	23	4,622,302	28	5,029,500	23
Natural gas physical contracts, net	8,427,119	10	21,504,378	10	1,666,800	9

__________


(a)	Term reflects the maximum forward period hedged.


(b)	2,480,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Based on June 30, 2017 prices, a $0.2 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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, which includes 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 in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	June 30, 2017			December 31, 2016			June 30, 2016
	Designated Interest Rate Swaps			Designated Interest Rate Swap^(a)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swaps ^(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			10			10			6
Derivative liabilities, current	$	—		$	90		$	8,553		$	18,500		$	1,505

__________


(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 and six months ended June 30, 2017 and 2016 (in thousands). Note that this presentation does not reflect 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 June 30, 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	$	(713	)	Interest expense	$	—
Commodity derivatives	Revenue	430			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(44		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(327	)		$	—



Three Months Ended June 30, 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	$	(840	)	Interest expense	$	—
Commodity derivatives	Revenue	3,287			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(61		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	2,386			$	—




Six Months Ended June 30, 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	$	(1,515	)	Interest expense	$	—
Commodity derivatives	Revenue	659			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	14			Fuel, purchased power and cost of natural gas sold	—
Total		$	(842	)		$	—




Six Months Ended June 30, 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	$	(1,690	)	Interest expense	$	—
Commodity derivatives	Revenue	6,939			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(151		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	5,098			$	—

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 and six months ended June 30, 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 June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(12,614	)
Forward commodity contracts	525			(2,452		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			840
Forward commodity contracts	(386		)	(3,226		)
Total other comprehensive income (loss) from hedging	$	852		$	(17,452	)



	Six Months Ended June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(30,665	)
Forward commodity contracts	1,451			(266		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	1,515			1,690
Forward commodity contracts	(673		)	6,788
Total other comprehensive income (loss) from hedging	$	2,293		$	(22,453	)

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 and six months ended June 30, 2017 and 2016 (in thousands). Note that this presentation does not reflect 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 June 30,
		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	$	26		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(691		)	2,201
		$	(665	)	$	2,201



		Six Months Ended June 30,
		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	$	143		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(1,500		)	2,835
		$	(1,357	)	$	2,835

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 $11 million, $8.8 million and $12 million at June 30, 2017, December 31, 2016 and June 30, 2016, respectively.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements:

6 Months Ended

Jun. 30, 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 June 30, 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 June 30, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas	$	—	$	770	$	—	$	(230	)	$	540
Commodity derivatives — Utilities	—		1,622		—		(977		)	645
Total	$	—	$	2,392	$	—	$	(1,207	)	$	1,185

Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	44	$	—	$	—		$	44
Commodity derivatives — Utilities	—		12,331		—		(11,568		)	763
Total	$	—	$	12,375	$	—	$	(11,568	)	$	807



	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
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 June 30, 2016
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas	$	—	$	2,748	$	—	$	(1,150	)	$	1,598
Commodity derivatives — Utilities	—		6,833		—		(4,175		)	2,658
Total	$	—	$	9,581	$	—	$	(5,325	)	$	4,256

Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	228	$	—	$	—		$	228
Commodity derivatives — Utilities	—		14,727		—		(14,427		)	300
Interest rate swaps	—		28,558		—		—			28,558
Total	$	—	$	43,513	$	—	$	(14,427	)	$	29,086

Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):



As of June 30, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	548	$	—
Commodity derivatives	Derivative assets — non-current	31		—
Commodity derivatives	Derivative liabilities — current	—		167
Commodity derivatives	Derivative liabilities — non-current	—		32
Total derivatives designated as hedges		$	579	$	199

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	600	$	—
Commodity derivatives	Derivative assets — non-current	6		—
Commodity derivatives	Derivative liabilities — current	—		552
Commodity derivatives	Derivative liabilities — non-current	—		56
Total derivatives not designated as hedges		$	606	$	608



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 June 30, 2016
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	2,549	$	—
Commodity derivatives	Derivative assets — non-current	81		—
Commodity derivatives	Derivative liabilities — current	—		44
Commodity derivatives	Derivative liabilities — non-current	—		226
Interest rate swaps	Derivative liabilities — current	—		28,558
Total derivatives designated as hedges		$	2,630	$	28,828

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	1,481	$	—
Commodity derivatives	Derivative assets — non-current	145		—
Commodity derivatives	Derivative liabilities — current	—		254
Commodity derivatives	Derivative liabilities — non-current	—		4
Total derivatives not designated as hedges		$	1,626	$	258

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 18 to the Consolidated Financial Statements included in our 2016 Annual Report on Form 10-K.

Fair Value of Financial Instruments:

6 Months Ended

Jun. 30, 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:



	June 30, 2017				December 31, 2016				June 30, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	11,590	$	11,590	$	13,580	$	13,580	$	61,859	$	61,859
Restricted cash and equivalents ^(a)	$	2,534	$	2,534	$	2,274	$	2,274	$	1,975	$	1,975
Notes payable ^(b)	$	107,975	$	107,975	$	96,600	$	96,600	$	75,000	$	75,000
Long-term debt, including current maturities, net of deferred financing costs ^(c)	$	3,166,045	$	3,377,891	$	3,216,932	$	3,351,305	$	3,152,090	$	3,427,587

__________


(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.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Other Comprehensive Income (Loss):

6 Months Ended

Jun. 30, 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						Six Months Ended
		June 30, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(840	)	$	(1,515	)	$	(1,690	)
Commodity contracts	Revenue	430			3,287			659			6,939
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(44		)	(61		)	14			(151		)
		(327		)	2,386			(842		)	5,098
Income tax	Income tax benefit (expense)	106			(882		)	281			(1,884		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	(221	)	$	1,504		$	(561	)	$	3,214

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	49		$	55		$	97		$	110
Actuarial gain (loss)	Operations and maintenance	(414		)	(494		)	(828		)	(989		)
		(365		)	(439		)	(731		)	(879		)
Income tax	Income tax benefit (expense)	128			154			265			308
Total reclassification adjustments related to defined benefit plans, net of tax		$	(237	)	$	(285	)	$	(466	)	$	(571	)
Total reclassifications		$	(458	)	$	1,219		$	(1,027	)	$	2,643

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	—			915			—			915
Amounts reclassified from AOCI	985			(424		)	466			1,027
Ending Balance June 30, 2017	$	(17,124	)	$	258		$	(16,075	)	$	(32,941	)


	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	(19,898		)	(168		)	—			(20,066		)
Amounts reclassified from AOCI	1,098			(4,312		)	571			(2,643		)
Ending Balance June 30, 2016	$	(19,141	)	$	2,586		$	(15,209	)	$	(31,764	)

- Definition

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=66004124&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e640-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e716-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e709-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e637-108580

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e681-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

+ Details

Supplemental Disclosure of Cash Flow Information:

6 Months Ended

Jun. 30, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Six Months Ended	June 30, 2017			June 30, 2016
	(in thousands)
Non-cash investing and financing activities—
Property, plant and equipment acquired with accrued liabilities	$	37,601		$	52,917

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(65,820	)	$	(48,139	)
Income taxes, net	$	1		$	(1,162	)

Employee Benefit Plans:

6 Months Ended

Jun. 30, 2017

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands):



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	1,759		$	2,078		$	3,517		$	4,156
Interest cost	3,880			3,936			7,760			7,872
Expected return on plan assets	(6,129		)	(5,766		)	(12,258		)	(11,531		)
Prior service cost	15			15			29			30
Net loss (gain)	1,001			1,793			2,003			3,586
Net periodic benefit cost	$	526		$	2,056		$	1,051		$	4,113

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	575		$	467		$	1,150		$	934
Interest cost	534			485			1,067			970
Expected return on plan assets	(79		)	(70		)	(158		)	(140		)
Prior service cost (benefit)	(109		)	(107		)	(218		)	(214		)
Net loss (gain)	125			84			250			168
Net periodic benefit cost	$	1,046		$	859		$	2,091		$	1,718

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Service cost	$	609	$	878	$	1,436	$	907
Interest cost	319		315		638		629
Prior service cost	—		1		1		1
Net loss (gain)	250		207		500		414
Net periodic benefit cost	$	1,178	$	1,401	$	2,575	$	1,951

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $13 million. 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		Contributions Made		Additional Contributions		Contributions
	Three Months Ended June 30, 2017		Six Months Ended June 30, 2017		Anticipated for 2017		Anticipated for 2018
Defined Benefit Pension Plan	$	—	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,270	$	2,540	$	2,540	$	5,115
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	396	$	792	$	792	$	1,682

Commitments and Contingencies:	6 Months Ended
Commitments and Contingencies:	Jun. 30, 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 June 30, 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 June 30, 2017, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $257 million.

Impairment of Assets:	6 Months Ended
Impairment of Assets:	Jun. 30, 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. There were no impairments for the six months ended June 30, 2017. 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 June 30, 2017, the average NYMEX natural gas price was $3.01 per Mcf, adjusted to $2.70 per Mcf at the wellhead; the average NYMEX crude oil price was $48.95 per barrel, adjusted to $44.42 per barrel at the wellhead. At June 30, 2016, the average NYMEX natural gas price was $2.24 per Mcf, adjusted to $1.01 per Mcf at the wellhead; the average NYMEX crude oil price was $43.12 per barrel, adjusted to $37.19 per barrel at the wellhead. During the three and six months ended June 30, 2016, we recorded pre-tax non-cash impairments of oil and gas assets included in our Oil and Gas segment of $11 million and $25 million, respectively. During the second quarter of 2016, in advancing our Oil and Gas strategy, certain non-core assets were identified that are not suitable for inclusion in a possible Cost of Service Gas program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above.

Income Taxes:

6 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

The effective tax rate differs from the federal statutory rate as follows:



	Three Months Ended June 30,
Tax (benefit) expense	2017		2016
Federal statutory rate	35.0	%	35.0	%
State income tax (net of federal tax effect) ^(a)	(0.1	)	16.9
Percentage depletion in excess of cost	(1.2	)	(5.9	)
Accounting for uncertain tax positions adjustment	—		1.9
Noncontrolling interest ^(b)	(3.1	)	(25.1	)
Tax credits ^(c)	(3.6	)	—
Effective tax rate adjustment ^(d)	4.4		1.7
Flow-through adjustments^(e)	(2.6	)	(10.6	)
AFUDC equity ^(f)	(0.6	)	(5.8	)
Other tax differences	0.9		0.5
	29.1	%	8.6	%

__________


(a)	In the three months ending June 30, 2017, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies.


(b)	The adjustment reflects the noncontrolling interest attributable to the sale of 49.9% of the membership interests of Colorado IPP in April 2016.


(c)	The increase in tax credits is due to Peak View Wind Project production tax credits and the marginal gas well tax credit on the oil and gas segment.


(d)	Adjustment to reflect the projected annual effective tax rate, pursuant to ASC 740-270.


(e)	In the three months ending June 30, 2016, the increase in flow-through was primarily attributable to the Section 263A change of accounting method 481(a) adjustment. This change resulted in a basis difference whose tax benefit is flowed through versus being normalized as federal tax depreciation.


(f)	In the three months ending June 30, 2016, AFUDC equity benefit increased primarily due to the Peak View Wind Project.

The lower pre-tax income for the second quarter of 2016 caused some of the percentages to not be reflective of the expected impact on full year operating results.




	Six Months Ended June 30,
Tax (benefit) expense	2017		2016
Federal statutory rate	35.0	%	35.0	%
State income tax (net of federal tax effect) ^(a)	1.0		3.8
Percentage depletion in excess of cost ^(b)	(0.6	)	(13.5	)
Accounting for uncertain tax positions adjustment ^(c)	—		(10.4	)
Noncontrolling interest ^(d)	(1.6	)	(1.9	)
IRC 172(f) carryback claim ^(e)	(1.3	)	—
Tax credits ^(f)	(1.8	)	—
Effective tax rate adjustment ^(g)	(0.8	)	(3.5	)
Flow-through adjustments ^(h)	(1.0	)	(1.7	)
Transaction costs	—		2.3
Other tax differences	0.4		(0.6	)
	29.3	%	9.5	%

__________


(a)	The state income tax expense is lower primarily attributable to favorable flow-through adjustments.


(b)	The tax benefit for the six months ended June 30, 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 six months ended June 30, 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% 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 six months ended June 30, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016.


(g)	Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270.

(h)

The flow-through adjustments related primarily to an accounting method change for tax purpose that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.

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:

6 Months Ended

Jun. 30, 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:



	June 30, 2017		December 31, 2016		June 30, 2016
Accrued employee compensation, benefits and withholdings	$	45,767	$	56,926	$	45,991
Accrued property taxes	34,683		40,004		33,295
Customer deposits and prepayments	41,067		51,628		44,200
Accrued interest and contract adjustment payments	33,914		45,503		42,330
CIAC current portion	1,575		—		20,211
Other (none of which is individually significant)	44,987		49,973		32,223
Total accrued liabilities	$	201,993	$	244,034	$	218,250

Management's Statement: (Policies)	6 Months Ended
Management's Statement: (Policies)	Jun. 30, 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 June 30, 2017, December 31, 2016, and June 30, 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 and six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017, December 31, 2016, and June 30, 2016, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. June 30, 2017 reflects a full six months of activity from the SourceGas Acquisition on February 12, 2016, as compared to the six months ended June 30, 2016 which reflects a partial period of approximately 4.5 months. 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 as of December 31, 2016. 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 $55 million as of June 30, 2016, and decreased net cash flows provided by operations by $39 million for the six months ended June 30, 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 June 30, 2016 and to the Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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. This ASU 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. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures, and we monitor regulated utility industry implementation discussions and guidance. 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. We will implement this standard effective January 1, 2018. 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). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. 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 a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. 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 currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. 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 revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect 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. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

Acquisition: (Tables)

6 Months Ended

Jun. 30, 2017

Business Combinations [Abstract]

Business Combination, Pro Forma Information



	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
	(in thousands, except per share amounts)
Revenue	$	325,441	$	854,362
Net income (loss) available for common stock	$	4,658	$	72,978
Earnings (loss) per share, Basic	$	0.09	$	1.42
Earnings (loss) per share, Diluted	$	0.09	$	1.39

Business Segment Information: (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	165,517	$	2,936		$	18,832
Gas	166,439		8			(272		)
Power Generation ^(b)	1,470		20,325			5,332
Mining	8,403		6,543			2,681
Oil and Gas	6,149		—			(1,946		)
Corporate activities ^(c)	—		—			(2,432		)
Inter-company eliminations	—		(29,812		)	—
Total	$	347,978	$	—		$	22,195



Three Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric^.	$	158,560	$	2,921		$	19,229
Gas	153,767		(1,806		)	987
Power Generation ^(b)	1,546		20,168			5,683
Mining	3,922		7,125			724
Oil and Gas ^(e)	7,646		—			(19,424		)
Corporate activities ^(c)	—		—			(6,530		)
Inter-company eliminations	—		(28,408		)	—
Total	$	325,441	$	—		$	669




Six Months Ended June 30, 2017	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	337,687	$	6,790		$	41,062
Gas ^(a)	531,340		17			45,738
Power Generation ^(b)	3,572		41,790			11,862
Mining	16,758		14,734			5,571
Oil and Gas	12,624		—			(4,897		)
Corporate activities ^(c)(d)	—		—			(618		)
Inter-company eliminations	—		(63,331		)	—
Total	$	901,981	$	—		$	98,718




Six Months Ended June 30, 2016	External Operating Revenue		Inter-company Operating Revenue			Net Income (Loss) Available for Common Stock
Segment:
Electric	$	322,091	$	6,666		$	38,444
Gas ^(a)	422,434		—			32,914
Power Generation ^(b)	3,398		41,624			14,265
Mining	11,456		15,873			3,662
Oil and Gas ^(e)	16,021		—			(26,448		)
Corporate activities ^(c)(d)	—		—			(22,166		)
Inter-company eliminations	—		(64,163		)	—
Total	$	775,400	$	—		$	40,671

___________


(a)	Gas Utility revenue increased for the six months ended June 30, 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 for the three and six months ended June 30, 2017 was net of net income attributable to noncontrolling interests of $3.1 million and $6.6 million, respectively, and $2.6 million for both the three and six months ended June 30, 2016.

(c)

(d)


(e)	Net income (loss) available for common stock for the three and six months ended June 30, 2016 included non-cash after-tax impairments of oil and gas properties of $16 million and $25 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:	June 30, 2017		December 31, 2016		June 30, 2016
Segment:
Electric ^(a)	$	2,901,570	$	2,859,559	$	2,755,695
Gas	3,242,461		3,307,967		3,118,626
Power Generation ^(a)	66,292		73,445		80,360
Mining	67,365		67,347		71,319
Oil and Gas ^(b)	103,044		96,435		171,239
Corporate activities	108,360		110,691		142,679
Total assets	$	6,489,092	$	6,515,444	$	6,339,918

__________


(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 $40 million for the six months ended June 30, 2016. See Note 17 to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Accounts Receivable: (Tables)

6 Months Ended

Jun. 30, 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
June 30, 2017	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	41,635	$	33,686	$	(466	)	$	74,855
Gas Utilities	62,908		26,584		(2,535		)	86,957
Power Generation	877		—		—			877
Mining	2,904		—		—			2,904
Oil and Gas	3,280		—		(83		)	3,197
Corporate	1,167		—		—			1,167
Total	$	112,771	$	60,270	$	(3,084	)	$	169,957



	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
June 30, 2016	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric Utilities	$	40,991	$	34,174	$	(716	)	$	74,449
Gas Utilities	47,600		23,124		(2,997		)	67,727
Power Generation	1,229		—		—			1,229
Mining	1,114		—		—			1,114
Oil and Gas	3,094		—		(13		)	3,081
Corporate	2,627		—		—			2,627
Total	$	96,655	$	57,298	$	(3,726	)	$	150,227

Regulatory Accounting: (Tables)

6 Months Ended

Jun. 30, 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	June 30, 2017		December 31, 2016		June 30, 2016
	(in years)
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	20,761	$	17,491	$	20,603
Deferred gas cost adjustments ^(a)(d)	1	9,060		15,329		12,122
Gas price derivatives ^(a)	3.5	11,159		8,843		11,515
Deferred taxes on AFUDC^(b)	45	15,322		15,227		13,879
Employee benefit plans ^(c)	12	107,419		108,556		109,522
Environmental^(a)	subject to approval	1,070		1,108		1,144
Asset retirement obligations^(a)	44	510		505		505
Loss on reacquired debt^(a)	30	21,466		22,266		3,061
Renewable energy standard adjustment ^(b)	5	768		1,605		2,679
Deferred taxes on flow through accounting^(c)	35	40,586		37,498		31,554
Decommissioning costs ^(e)	6	14,681		16,859		18,399
Gas supply contract termination	5	22,793		26,666		28,385
Other regulatory assets^{(a) (e)}	15	31,565		24,189		22,044
		$	297,160	$	296,142	$	275,412

Regulatory liabilities
Deferred energy and gas costs^{(a) (d)}	1	$	16,767	$	10,368	$	32,868
Employee benefit plan costs and related deferred taxes^(c)	12	67,297		68,654		62,712
Cost of removal^(a)	44	125,247		118,410		126,002
Revenue subject to refund	1	1,518		2,485		1,616
Other regulatory liabilities^(c)	25	5,481		6,839		6,243
		$	216,310	$	206,756	$	229,441

__________


(a)	We are allowed 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)

(e)

Materials, Supplies and Fuel: (Tables)

6 Months Ended

Jun. 30, 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:



	June 30, 2017		December 31, 2016		June 30, 2016
Materials and supplies	$	72,397	$	68,456	$	67,440
Fuel - Electric Utilities	3,106		3,667		4,659
Natural gas in storage held for distribution	23,623		35,087		13,090
Total materials, supplies and fuel	$	99,126	$	107,210	$	85,189

Earnings Per Share: (Tables)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016

Net income (loss) available for common stock	$	22,195	$	669	$	98,718	$	40,671

Weighted average shares - basic	53,229		51,514		53,191		51,279
Dilutive effect of:
Equity Units ^(a)	1,977		1,362		1,796		1,068
Equity compensation	178		110		192		107
Weighted average shares - diluted	55,384		52,986		55,179		52,454

__________


(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 June 30,		Six Months Ended June 30,
	2017	2016	2017	2016

Equity compensation	—	4	—	10
Anti-dilutive shares	—	4	—	10

Notes Payable And Long-term Debt: (Tables)

6 Months Ended

Jun. 30, 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:



	June 30, 2017				December 31, 2016				June 30, 2016
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	—	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700
CP Program	107,975		—		—		—		—		—
Total	$	107,975	$	24,540	$	96,600	$	36,000	$	75,000	$	24,700

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 June 30, 2017	Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio	61%	Less than	65%

Equity: (Tables)

6 Months Ended

Jun. 30, 2017

Statement of Stockholders' Equity [Abstract]

Schedule of Stockholders Equity

A summary of the changes in equity is as follows:



Six Months Ended June 30, 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)	98,718			6,632			105,350
Other comprehensive income (loss)	1,942			—			1,942
Dividends on common stock	(47,544		)	—			(47,544		)
Share-based compensation	4,133			—			4,133
Issuance of common stock	—			—			—
Dividend reinvestment and stock purchase plan	1,530			—			1,530
Redeemable noncontrolling interest	(886		)	—			(886		)
Cumulative effect of ASU 2016-09 implementation	3,714			—			3,714
Other stock transactions	(7		)	—			(7		)
Distribution to noncontrolling interest	—			(8,335		)	(8,335		)
Balance at June 30, 2017	$	1,676,239		$	113,792		$	1,790,031



Six Months Ended June 30, 2016	Total Stockholders’ Equity			Noncontrolling Interest		Total Equity
				(in thousands)
Balance at December 31, 2015	$	1,465,867		$	—	$	1,465,867
Net income (loss)	40,671			2,632		43,303
Other comprehensive income (loss)	(22,709		)	—		(22,709		)
Dividends on common stock	(43,270		)	—		(43,270		)
Share-based compensation	2,192			—		2,192
Issuance of common stock	55,802			—		55,802
Dividend reinvestment and stock purchase plan	1,478			—		1,478
Other stock transactions	(20		)	—		(20		)
Sale of noncontrolling interest	62,416			114,886		177,302
Balance at June 30, 2016	$	1,562,427		$	117,518	$	1,679,945

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:



	June 30, 2017		December 31, 2016		June 30, 2016
	(in thousands)
Assets
Current assets	$	12,042	$	12,627	$	12,681
Property, plant and equipment of variable interest entities, net	$	214,239	$	218,798	$	224,128

Liabilities
Current liabilities	$	2,651	$	4,342	$	4,174

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Risk Management Activities: (Tables)

6 Months Ended

Jun. 30, 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:



	June 30, 2017			December 31, 2016			June 30, 2016
	Designated Interest Rate Swaps			Designated Interest Rate Swap^(a)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swap ^(b)			Designated Interest Rate Swaps ^(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			10			10			6
Derivative liabilities, current	$	—		$	90		$	8,553		$	18,500		$	1,505

__________


(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



	June 30, 2017		December 31, 2016		June 30, 2016
	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)	Notional (MMBtus)	Maximum Term (months)^(a)
Natural gas futures purchased	11,060,000	42	14,770,000	48	18,080,000	54
Natural gas options purchased, net	1,640,000	20	3,020,000	5	3,770,000	20
Natural gas basis swaps purchased	10,070,000	42	12,250,000	48	15,320,000	54
Natural gas over-the-counter swaps, net ^(b)	5,200,000	23	4,622,302	28	5,029,500	23
Natural gas physical contracts, net	8,427,119	10	21,504,378	10	1,666,800	9

__________


(a)	Term reflects the maximum forward period hedged.


(b)	2,480,000 MMBtus were designated as cash flow hedges for the natural gas fixed for float swaps purchased.

Derivative Instruments, Gain (Loss)



Three Months Ended June 30, 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	$	(713	)	Interest expense	$	—
Commodity derivatives	Revenue	430			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(44		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	(327	)		$	—



Three Months Ended June 30, 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	$	(840	)	Interest expense	$	—
Commodity derivatives	Revenue	3,287			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(61		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	2,386			$	—




Six Months Ended June 30, 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	$	(1,515	)	Interest expense	$	—
Commodity derivatives	Revenue	659			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	14			Fuel, purchased power and cost of natural gas sold	—
Total		$	(842	)		$	—




Six Months Ended June 30, 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	$	(1,690	)	Interest expense	$	—
Commodity derivatives	Revenue	6,939			Revenue	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(151		)	Fuel, purchased power and cost of natural gas sold	—
Total		$	5,098			$	—



	Three Months Ended June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(12,614	)
Forward commodity contracts	525			(2,452		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	713			840
Forward commodity contracts	(386		)	(3,226		)
Total other comprehensive income (loss) from hedging	$	852		$	(17,452	)



	Six Months Ended June 30,
	2017			2016
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	—		$	(30,665	)
Forward commodity contracts	1,451			(266		)
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	1,515			1,690
Forward commodity contracts	(673		)	6,788
Total other comprehensive income (loss) from hedging	$	2,293		$	(22,453	)

Derivatives Not Designated as Hedge Instruments



		Three Months Ended June 30,
		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	$	26		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(691		)	2,201
		$	(665	)	$	2,201



		Six Months Ended June 30,
		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	$	143		$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(1,500		)	2,835
		$	(1,357	)	$	2,835

Oil and Gas

Derivative [Line Items]

Schedule of Derivative Instruments

We had the following short positions as of:



	June 30, 2017			December 31, 2016			June 30, 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)	72,000	18,000	1,080,000	108,000	36,000	2,700,000	210,000	2,530,000
Maximum terms in months ^(b)	18	6	6	24	12	12	30	18

__________


(a)	Crude oil futures and call options in Bbls, natural gas in MMBtus.


(b)	Term reflects the maximum forward period hedged.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=64837297&loc=SL5579240-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64837297&loc=d3e41620-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements: (Tables)

6 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value Hierarchy, Measured on Recurring Basis



	As of June 30, 2017
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas	$	—	$	770	$	—	$	(230	)	$	540
Commodity derivatives — Utilities	—		1,622		—		(977		)	645
Total	$	—	$	2,392	$	—	$	(1,207	)	$	1,185

Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	44	$	—	$	—		$	44
Commodity derivatives — Utilities	—		12,331		—		(11,568		)	763
Total	$	—	$	12,375	$	—	$	(11,568	)	$	807



	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
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 June 30, 2016
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
	(in thousands)
Assets:
Commodity derivatives — Oil and Gas	$	—	$	2,748	$	—	$	(1,150	)	$	1,598
Commodity derivatives — Utilities	—		6,833		—		(4,175		)	2,658
Total	$	—	$	9,581	$	—	$	(5,325	)	$	4,256

Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	228	$	—	$	—		$	228
Commodity derivatives — Utilities	—		14,727		—		(14,427		)	300
Interest rate swaps	—		28,558		—		—			28,558
Total	$	—	$	43,513	$	—	$	(14,427	)	$	29,086

Schedule of Derivative Instruments Balance Sheet Location

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):



As of June 30, 2017
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	548	$	—
Commodity derivatives	Derivative assets — non-current	31		—
Commodity derivatives	Derivative liabilities — current	—		167
Commodity derivatives	Derivative liabilities — non-current	—		32
Total derivatives designated as hedges		$	579	$	199

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	600	$	—
Commodity derivatives	Derivative assets — non-current	6		—
Commodity derivatives	Derivative liabilities — current	—		552
Commodity derivatives	Derivative liabilities — non-current	—		56
Total derivatives not designated as hedges		$	606	$	608



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 June 30, 2016
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	2,549	$	—
Commodity derivatives	Derivative assets — non-current	81		—
Commodity derivatives	Derivative liabilities — current	—		44
Commodity derivatives	Derivative liabilities — non-current	—		226
Interest rate swaps	Derivative liabilities — current	—		28,558
Total derivatives designated as hedges		$	2,630	$	28,828

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	1,481	$	—
Commodity derivatives	Derivative assets — non-current	145		—
Commodity derivatives	Derivative liabilities — current	—		254
Commodity derivatives	Derivative liabilities — non-current	—		4
Total derivatives not designated as hedges		$	1,626	$	258

Fair Value of Financial Instruments: (Tables)

6 Months Ended

Jun. 30, 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:



	June 30, 2017				December 31, 2016				June 30, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents ^(a)	$	11,590	$	11,590	$	13,580	$	13,580	$	61,859	$	61,859
Restricted cash and equivalents ^(a)	$	2,534	$	2,534	$	2,274	$	2,274	$	1,975	$	1,975
Notes payable ^(b)	$	107,975	$	107,975	$	96,600	$	96,600	$	75,000	$	75,000
Long-term debt, including current maturities, net of deferred financing costs ^(c)	$	3,166,045	$	3,377,891	$	3,216,932	$	3,351,305	$	3,152,090	$	3,427,587

__________


(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 (Loss): (Tables)

6 Months Ended

Jun. 30, 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						Six Months Ended
		June 30, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(713	)	$	(840	)	$	(1,515	)	$	(1,690	)
Commodity contracts	Revenue	430			3,287			659			6,939
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(44		)	(61		)	14			(151		)
		(327		)	2,386			(842		)	5,098
Income tax	Income tax benefit (expense)	106			(882		)	281			(1,884		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	(221	)	$	1,504		$	(561	)	$	3,214

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	49		$	55		$	97		$	110
Actuarial gain (loss)	Operations and maintenance	(414		)	(494		)	(828		)	(989		)
		(365		)	(439		)	(731		)	(879		)
Income tax	Income tax benefit (expense)	128			154			265			308
Total reclassification adjustments related to defined benefit plans, net of tax		$	(237	)	$	(285	)	$	(466	)	$	(571	)
Total reclassifications		$	(458	)	$	1,219		$	(1,027	)	$	2,643

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	—			915			—			915
Amounts reclassified from AOCI	985			(424		)	466			1,027
Ending Balance June 30, 2017	$	(17,124	)	$	258		$	(16,075	)	$	(32,941	)


	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	(19,898		)	(168		)	—			(20,066		)
Amounts reclassified from AOCI	1,098			(4,312		)	571			(2,643		)
Ending Balance June 30, 2016	$	(19,141	)	$	2,586		$	(15,209	)	$	(31,764	)

Supplemental Disclosure of Cash Flow Information: (Tables)

6 Months Ended

Jun. 30, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information



Six Months Ended	June 30, 2017			June 30, 2016
	(in thousands)
Non-cash investing and financing activities—
Property, plant and equipment acquired with accrued liabilities	$	37,601		$	52,917

Cash (paid) refunded during the period —
Interest (net of amounts capitalized)	$	(65,820	)	$	(48,139	)
Income taxes, net	$	1		$	(1,162	)

Employee Benefit Plans: (Tables)

6 Months Ended

Jun. 30, 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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	1,759		$	2,078		$	3,517		$	4,156
Interest cost	3,880			3,936			7,760			7,872
Expected return on plan assets	(6,129		)	(5,766		)	(12,258		)	(11,531		)
Prior service cost	15			15			29			30
Net loss (gain)	1,001			1,793			2,003			3,586
Net periodic benefit cost	$	526		$	2,056		$	1,051		$	4,113

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	575		$	467		$	1,150		$	934
Interest cost	534			485			1,067			970
Expected return on plan assets	(79		)	(70		)	(158		)	(140		)
Prior service cost (benefit)	(109		)	(107		)	(218		)	(214		)
Net loss (gain)	125			84			250			168
Net periodic benefit cost	$	1,046		$	859		$	2,091		$	1,718

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Service cost	$	609	$	878	$	1,436	$	907
Interest cost	319		315		638		629
Prior service cost	—		1		1		1
Net loss (gain)	250		207		500		414
Net periodic benefit cost	$	1,178	$	1,401	$	2,575	$	1,951

Schedule of Defined Benefit Plans Contributions

Contributions made in 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):



	Contributions Made		Contributions Made		Additional Contributions		Contributions
	Three Months Ended June 30, 2017		Six Months Ended June 30, 2017		Anticipated for 2017		Anticipated for 2018
Defined Benefit Pension Plan	$	—	$	—	$	12,700	$	12,700
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,270	$	2,540	$	2,540	$	5,115
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans	$	396	$	792	$	792	$	1,682

Income Taxes: (Tables)

6 Months Ended

Jun. 30, 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 June 30,
Tax (benefit) expense	2017		2016
Federal statutory rate	35.0	%	35.0	%
State income tax (net of federal tax effect) ^(a)	(0.1	)	16.9
Percentage depletion in excess of cost	(1.2	)	(5.9	)
Accounting for uncertain tax positions adjustment	—		1.9
Noncontrolling interest ^(b)	(3.1	)	(25.1	)
Tax credits ^(c)	(3.6	)	—
Effective tax rate adjustment ^(d)	4.4		1.7
Flow-through adjustments^(e)	(2.6	)	(10.6	)
AFUDC equity ^(f)	(0.6	)	(5.8	)
Other tax differences	0.9		0.5
	29.1	%	8.6	%

__________


(a)	In the three months ending June 30, 2017, the state income tax benefit is primarily attributable to favorable flow-through adjustments and a pretax net loss at state tax accruing companies.


(b)	The adjustment reflects the noncontrolling interest attributable to the sale of 49.9% of the membership interests of Colorado IPP in April 2016.


(c)	The increase in tax credits is due to Peak View Wind Project production tax credits and the marginal gas well tax credit on the oil and gas segment.


(d)	Adjustment to reflect the projected annual effective tax rate, pursuant to ASC 740-270.


(e)	In the three months ending June 30, 2016, the increase in flow-through was primarily attributable to the Section 263A change of accounting method 481(a) adjustment. This change resulted in a basis difference whose tax benefit is flowed through versus being normalized as federal tax depreciation.


(f)	In the three months ending June 30, 2016, AFUDC equity benefit increased primarily due to the Peak View Wind Project.

The lower pre-tax income for the second quarter of 2016 caused some of the percentages to not be reflective of the expected impact on full year operating results.




	Six Months Ended June 30,
Tax (benefit) expense	2017		2016
Federal statutory rate	35.0	%	35.0	%
State income tax (net of federal tax effect) ^(a)	1.0		3.8
Percentage depletion in excess of cost ^(b)	(0.6	)	(13.5	)
Accounting for uncertain tax positions adjustment ^(c)	—		(10.4	)
Noncontrolling interest ^(d)	(1.6	)	(1.9	)
IRC 172(f) carryback claim ^(e)	(1.3	)	—
Tax credits ^(f)	(1.8	)	—
Effective tax rate adjustment ^(g)	(0.8	)	(3.5	)
Flow-through adjustments ^(h)	(1.0	)	(1.7	)
Transaction costs	—		2.3
Other tax differences	0.4		(0.6	)
	29.3	%	9.5	%

__________


(a)	The state income tax expense is lower primarily attributable to favorable flow-through adjustments.


(b)	The tax benefit for the six months ended June 30, 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)


(d)	Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision 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 six months ended June 30, 2017 are the result of Colorado Electric placing the Peak View Wind Project into service in November 2016. The Peak View Wind Project began generating production tax credits during the fourth quarter of 2016.


(g)	Adjustment to reflect our 2017 and 2016 annual projected effective tax rate, pursuant to ASC 740-270.

(h)

Accrued Liabilities: (Tables)

6 Months Ended

Jun. 30, 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:



	June 30, 2017		December 31, 2016		June 30, 2016
Accrued employee compensation, benefits and withholdings	$	45,767	$	56,926	$	45,991
Accrued property taxes	34,683		40,004		33,295
Customer deposits and prepayments	41,067		51,628		44,200
Accrued interest and contract adjustment payments	33,914		45,503		42,330
CIAC current portion	1,575		—		20,211
Other (none of which is individually significant)	44,987		49,973		32,223
Total accrued liabilities	$	201,993	$	244,034	$	218,250

Management's Statement: Revisions (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities	$ 262,869	$ 183,503
Restatement Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Operating Activities		$ (39,000)
Cash and Cash Equivalents
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Prior Period Reclassification Adjustment	(55,000)
Accounts Payable
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Prior Period Reclassification Adjustment	$ (55,000)

Management's Statement: Improvements To Employee Share-Based Payment Accounting (Details) $ in Millions	Jan. 01, 2017 USD ($)
Adjustments for New Accounting Pronouncement
Retained Earnings Adjustments [Line Items]
Cumulative Effect on Retained Earnings, Net of Tax	$ 3.2

Acquisition: (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended	6 Months Ended
	Feb. 12, 2016	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Acquisition Narrative [Abstract]
Business Combination, Consideration Transferred, Net of Long Term Debt and Cash Acquired			$ 0	$ 1,124,238
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		$ 325,441		854,362
Pro Forma - Net income (loss) available for common stock		$ 4,658		$ 72,978
Pro Forma - Earnings per share, Basic (usd per share)		$ 0.09		$ 1.42
Pro Forma - Earnings per share, Diluted (usd per share)		$ 0.09		$ 1.39
Business Combination, Acquisition Related Costs		$ 4,000		$ 20,000

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

Business Segment Information: Information Relating to Segment Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Segment Reporting Information
Revenue	$ 347,978	$ 325,441	$ 901,981	$ 775,400
Net income (loss) available for common stock	22,195	669	98,718	40,671
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	3,116	2,614	6,739	2,662
Net tax benefit		4,400
Tax benefit recognized from Carryback claims for specified liability losses involving prior tax years			1,400
Inter-company eliminations
Segment Reporting Information
Revenue	(29,812)	(28,408)	(63,331)	(64,163)
Net income (loss) available for common stock	0	0	0	0
Corporate
Segment Reporting Information
Revenue	0	0	0	0
Net income (loss) available for common stock	(2,432)	(6,530)	(618)	(22,166)
Corporate \| Incremental, Non-Recurring Acquisition Costs (Net of Tax)
Segment Reporting Information
Business Combination, Acquisition Related Costs	300	4,100	1,200	20,000
Corporate \| Labor (Net Of Tax)
Segment Reporting Information
Business Combination, Acquisition Related Costs		2,000		5,700
Consolidation, Eliminations
Segment Reporting Information
Revenue	0	0	0	0
Electric Utilities
Segment Reporting Information
Revenue	165,517	158,560	337,687	322,091
Net income (loss) available for common stock	18,832	19,229	41,062	38,444
Electric Utilities \| Inter-company eliminations
Segment Reporting Information
Revenue	2,936	2,921	6,790	6,666
Gas Utilities
Segment Reporting Information
Revenue	166,439	153,767	531,340	422,434
Net income (loss) available for common stock	(272)	987	45,738	32,914
Gas Utilities \| Inter-company eliminations
Segment Reporting Information
Revenue	8	(1,806)	17	0
Power Generation
Segment Reporting Information
Revenue	1,470	1,546	3,572	3,398
Net income (loss) available for common stock	5,332	5,683	11,862	14,265
Net Income (Loss) Attributable to Redeemable Noncontrolling Interest	(3,100)	(2,600)	(6,600)	(2,600)
Power Generation \| Inter-company eliminations
Segment Reporting Information
Revenue	20,325	20,168	41,790	41,624
Mining
Segment Reporting Information
Revenue	8,403	3,922	16,758	11,456
Net income (loss) available for common stock	2,681	724	5,571	3,662
Mining \| Inter-company eliminations
Segment Reporting Information
Revenue	6,543	7,125	14,734	15,873
Oil and Gas
Segment Reporting Information
Revenue	6,149	7,646	12,624	16,021
Net income (loss) available for common stock	(1,946)	(19,424)	(4,897)	(26,448)
Impairment of Oil and Gas Properties Net of Tax		16,000		25,000
Oil and Gas \| Inter-company eliminations
Segment Reporting Information
Revenue	$ 0	$ 0	$ 0	$ 0

Business Segment Information: Segment and Corporate Assets (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 6,489,092	$ 6,339,918	$ 6,489,092	$ 6,339,918	$ 6,515,444
Impairment of long-lived assets	0	25,497	0	39,993
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	108,360	142,679	108,360	142,679	110,691
Electric Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	2,901,570	2,755,695	2,901,570	2,755,695	2,859,559
Gas Utilities
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	3,242,461	3,118,626	3,242,461	3,118,626	3,307,967
Power Generation
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	66,292	80,360	66,292	80,360	73,445
Mining
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	67,365	71,319	67,365	71,319	67,347
Oil and Gas
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 103,044	$ 171,239	$ 103,044	171,239	96,435
Impairment of long-lived assets				$ 40,000	$ 107,000

Accounts Receivable: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 112,771	$ 140,889	$ 96,655
Unbilled Receivables, Current	60,270	124,792	57,298
Allowance for Doubtful Accounts	(3,084)	(2,392)	(3,726)
Accounts receivable, net	169,957	263,289	150,227
Corporate
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,167	2,228	2,627
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	1,167	2,228	2,627
Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	41,635	41,730	40,991
Unbilled Receivables, Current	33,686	36,463	34,174
Allowance for Doubtful Accounts	(466)	(353)	(716)
Accounts receivable, net	74,855	77,840	74,449
Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	62,908	88,168	47,600
Unbilled Receivables, Current	26,584	88,329	23,124
Allowance for Doubtful Accounts	(2,535)	(2,026)	(2,997)
Accounts receivable, net	86,957	174,471	67,727
Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	877	1,420	1,229
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	877	1,420	1,229
Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,904	3,352	1,114
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	0	0	0
Accounts receivable, net	2,904	3,352	1,114
Oil and Gas
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,280	3,991	3,094
Unbilled Receivables, Current	0	0	0
Allowance for Doubtful Accounts	(83)	(13)	(13)
Accounts receivable, net	$ 3,197	$ 3,978	$ 3,081

Regulatory Accounting: (Details) - USD ($) $ in Thousands		6 Months Ended
Regulatory Accounting: (Details) - USD ($) $ in Thousands	Jul. 01, 2017	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 297,160	$ 296,142	$ 275,412
Regulatory Liabilities		$ 216,310	206,756	229,441
Subsequent Event
Schedule Of Regulatory Assets And Liabilities [Line Items]
Approximate increase in annual amortization expense due to change in amortization periods	$ 2,700
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Liabilities		$ 16,767	10,368	32,868
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Liabilities		$ 67,297	68,654	62,712
Cost of removal
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Liabilities		$ 125,247	118,410	126,002
Revenue Subject to Refund
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Liabilities		$ 1,518	2,485	1,616
Other regulatory liabilities
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		25 years
Regulatory Liabilities		$ 5,481	6,839	6,243
Deferred energy and gas costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets		$ 20,761	17,491	20,603
Deferred gas cost adjustments
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		1 year
Regulatory Assets		$ 9,060	15,329	12,122
Gas price derivatives
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		3 years 6 months
Regulatory Assets		$ 11,159	8,843	11,515
AFUDC
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		45 years
Regulatory Assets		$ 15,322	15,227	13,879
Employee benefit plans
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		12 years
Regulatory Assets		$ 107,419	108,556	109,522
Environmental
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 1,070	1,108	1,144
Asset retirement obligations
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		44 years
Regulatory Assets		$ 510	505	505
Loss on reacquired debt
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		30 years
Regulatory Assets		$ 21,466	22,266	3,061
Renewable energy standard adjustment
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets		$ 768	1,605	2,679
Flow through accounting
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		35 years
Regulatory Assets		$ 40,586	37,498	31,554
Decommissioning costs
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		6 years
Regulatory Assets		$ 14,681	16,859	18,399
Decommissioning costs \| South Dakota Public Utilities Commission (SDPUC)
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 11,000
Decommissioning costs \| South Dakota Public Utilities Commission (SDPUC) \| Subsequent Event
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	6 years
Decommissioning costs \| South Dakota Public Utilities Commission (SDPUC) \| Scenario, Previously Reported
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		10 years
Gas Supply Contract Termination
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		5 years
Regulatory Assets		$ 22,793	26,666	28,385
Other regulatory assets
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		15 years
Regulatory Assets		$ 31,565	$ 24,189	$ 22,044
Other regulatory assets \| South Dakota Public Utilities Commission (SDPUC)
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		14,000
Other regulatory assets \| South Dakota Public Utilities Commission (SDPUC) \| Subsequent Event
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	6 years
Other regulatory assets \| South Dakota Public Utilities Commission (SDPUC) \| Winter Storm Atlas
Schedule Of Regulatory Assets And Liabilities [Line Items]
Regulatory Assets		$ 2,000
Other regulatory assets \| South Dakota Public Utilities Commission (SDPUC) \| Winter Storm Atlas \| Subsequent Event
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period	6 years
Other regulatory assets \| South Dakota Public Utilities Commission (SDPUC) \| Winter Storm Atlas \| Scenario, Previously Reported
Schedule Of Regulatory Assets And Liabilities [Line Items]
Maximum Amortization Period		10 years

Materials, Supplies and Fuel: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Inventory, Net [Abstract]
Materials and supplies	$ 72,397	$ 68,456	$ 67,440
Fuel - Electric Utilities	3,106	3,667	4,659
Natural gas in storage held for distribution	23,623	35,087	13,090
Total materials, supplies and fuel	$ 99,126	$ 107,210	$ 85,189

Earnings Per Share: Earnings Per Share Reconciliation (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Earnings Per Share [Abstract]
Net income (loss) available for common stock	$ 22,195	$ 669	$ 98,718	$ 40,671
Weighted average shares - basic (in shares)	53,229	51,514	53,191	51,279
Dilutive effect of:
Equity Units (in shares)	1,977	1,362	1,796	1,068
Equity compensation (in shares)	178	110	192	107
Weighted average shares - diluted (in shares)	55,384	52,986	55,179	52,454

Earnings Per Share: Anti-dilutive shares (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0	10	0	4
Stock Compensation Plan
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Anti-dilutive shares	0	10	0	4

Notes Payable And Long-term Debt: Schedule of Short-term Debt and Narrative (Details)		6 Months Ended
	Aug. 09, 2016 USD ($) credit_extension	Jun. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 22, 2016 USD ($)	Aug. 08, 2016 USD ($)	Jun. 30, 2016 USD ($)
Short-term Debt [Line Items]
Notes payable		$ 107,975,000	$ 96,600,000			$ 75,000,000
Letters of Credit		24,540,000	36,000,000			24,700,000
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			75,000,000
Letters of Credit		24,540,000	36,000,000			24,700,000
Line of Credit Facility, Current Borrowing Capacity	$ 750,000,000				$ 500,000,000
Number Of One-Year Extension Options \| credit_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%
CP Program
Short-term Debt [Line Items]
Notes payable		$ 107,975,000	$ 0			$ 0
Debt Instrument, Term		397 days
Short-term Debt, Weighted Average Interest Rate		1.41%

Notes Payable And Long-term Debt: Debt covenants (Details)	Jun. 30, 2017
Revolving Credit Facility
Line of Credit Facility [Line Items]
Recourse Leverage Ratio	61.00%
Debt instrument, covenant, Leverage Recourse Ratio	0.65
Maximum
Line of Credit Facility [Line Items]
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year	0.65

Notes Payable And Long-term Debt: Long-Term Debt (Details) - Corporate Term Loan Due August 2019 - USD ($) $ in Millions		6 Months Ended
	Jul. 17, 2017	Jun. 30, 2017
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 50
Subsequent Event
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 50

Equity: Stockholders Equity Recap (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 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	$ 22,195	$ 669	98,718	40,671
Net Income (Loss) Attributable to Noncontrolling Interest	3,116	2,614	6,739	2,662
Net Income (Loss) Including Portion Attributable to Noncontrolling Interest (Excluding Income Loss Attributable to Redeemable Noncontrolling Interest)			105,350	43,303
Other comprehensive income (loss)	789	(10,939)	1,942	(22,709)
Dividends on common stock			(47,544)	(43,270)
Share-based compensation			4,133	2,192
Issuance of common stock			0	55,802
Dividend reinvestment and stock purchase plan			1,530	1,478
Redeemable noncontrolling interest			(886)
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net			3,714
Other stock transactions			(7)	(20)
Distribution to noncontrolling interest			(8,335)
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				177,302
Total Stockholders' Equity, ending balance	1,676,239	1,562,427	1,676,239	1,562,427
Noncontrolling Interest, ending balance	113,792	117,518	113,792	117,518
Total Equity, ending balance	1,790,031	1,679,945	1,790,031	1,679,945
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			98,718	40,671
Other comprehensive income (loss)			1,942	(22,709)
Dividends on common stock			(47,544)	(43,270)
Share-based compensation			4,133	2,192
Issuance of common stock			0	55,802
Dividend reinvestment and stock purchase plan			1,530	1,478
Redeemable noncontrolling interest			(886)
Adjustment to Additional Paid in Capital, Income Tax Effect from Share-based Compensation, Net			3,714
Other stock transactions			(7)	(20)
Distribution to noncontrolling interest			0
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				62,416
Total Stockholders' Equity, ending balance	1,676,239	1,562,427	1,676,239	1,562,427
Noncontrolling Interest
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Noncontrolling Interest, beginning balance			115,495	0
Net Income (Loss) Attributable to Noncontrolling Interest			6,632	2,632
Other comprehensive income (loss)			0	0
Dividends on common stock			0	0
Share-based compensation			0	0
Issuance of common stock			0	0
Dividend reinvestment and stock purchase plan			0	0
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			(8,335)
Noncontrolling Interest, Increase from Sale of Parent Equity Interest				114,886
Noncontrolling Interest, ending balance	$ 113,792	$ 117,518	$ 113,792	$ 117,518

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Aug. 04, 2017	Mar. 18, 2016
At The Market Equity Offering Program Authorized Aggregate Value				$ 200.0
Payments of Stock Issuance Costs	$ 0.5	$ 0.6
Common Stock
At The Market Equity Offering Program Shares Issued	809,649	930,649
At the Market Equity Program - Proceeds From Sale of Stock	$ 49.0	$ 56.0
Subsequent Event
At The Market Equity Offering Program Authorized Aggregate Value			$ 300.0

Equity: Variable Interest Entities (Details) $ in Thousands		3 Months Ended	6 Months Ended
Equity: Variable Interest Entities (Details) $ in Thousands	Apr. 14, 2016 USD ($)	Jun. 30, 2016 USD ($) MW	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage		49.90%		49.90%
Sale of noncontrolling interest			$ 0	$ 216,370
Current assets		$ 388,788	359,256	388,788	$ 466,814
Property, plant and equipment of variable interest entities, net		6,209,816	6,533,581	6,209,816	6,412,223
Current liabilities		$ 1,412,950	438,865	1,412,950	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		$ 12,681	12,042	12,681	12,627
Property, plant and equipment of variable interest entities, net		224,128	214,239	224,128	218,798
Current liabilities		$ 4,174	$ 2,651	$ 4,174	$ 4,342

Risk Management Activities: Oil and Gas (Details) - Oil and Gas $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016 MMBTU bbl	Jun. 30, 2017 USD ($) MMBTU bbl	Dec. 31, 2016 MMBTU bbl
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months \| $		$ 0.5
Swaps and Options \| Crude Oil
Derivative [Line Items]
Notional amount - commodities	210,000	72,000	108,000
Maximum Term Hedged in Cash Flow Hedge	30 months	18 months	24 months
Options Held \| Crude Oil
Derivative [Line Items]
Notional amount - commodities		18,000	36,000
Maximum Term Hedged in Cash Flow Hedge		6 months	12 months
Swap \| Natural Gas
Derivative [Line Items]
Notional amount - commodities \| MMBTU	2,530,000	1,080,000	2,700,000
Maximum Term Hedged in Cash Flow Hedge	18 months	6 months	12 months

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions	6 Months Ended		12 Months Ended
	Jun. 30, 2017 USD ($) MMBTU	Jun. 30, 2016 MMBTU	Dec. 31, 2016 MMBTU
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months \| $	$ 0.2
Cash Flow Hedging
Derivative [Line Items]
Notional amount - commodities	2,480,000
Future
Derivative [Line Items]
Notional amount - commodities	11,060,000	18,080,000	14,770,000
Maximum Term	42 months	54 months	48 months
Commodity Option
Derivative [Line Items]
Notional amount - commodities	1,640,000	3,770,000	3,020,000
Maximum Term	20 months	20 months	5 months
Basis Swap
Derivative [Line Items]
Notional amount - commodities	10,070,000	15,320,000	12,250,000
Maximum Term	42 months	54 months	48 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Notional amount - commodities	5,200,000	5,029,500	4,622,302
Maximum Term	23 months	23 months	28 months
Natural Gas Physical Purchases
Derivative [Line Items]
Notional amount - commodities	8,427,119	1,666,800	21,504,378
Maximum Term	10 months	9 months	10 months

Risk Management Activities: Financing Activities (Details) - USD ($) $ in Thousands				6 Months Ended		12 Months Ended
	Aug. 19, 2016	Aug. 10, 2016	Aug. 09, 2016	Jun. 30, 2017	Jun. 30, 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 liabilities, current				719	$ 28,855	$ 2,459
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 Three
Derivative [Line Items]
Notional Amount					$ 150,000
Weighted average fixed interest rate					2.09%
Maximum Term					10 months
Derivative liabilities, current					$ 8,553
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					10 months
Derivative liabilities, current					$ 18,500
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 liabilities, current				$ 0		$ 90
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					6 months
Derivative liabilities, current					$ 1,505

Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 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 Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	$ (327)	$ 2,386	(842)	$ 5,098
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0	0
Cash Flow Hedging \| Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	852	(17,452)	2,293	(22,453)
Cash Flow Hedging \| Interest Rate Swap \| Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	713	840	1,515	1,690
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	0	(12,614)	0	(30,665)
Cash Flow Hedging \| Interest Rate Swap \| Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(713)	(840)	(1,515)	(1,690)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0	0
Cash Flow Hedging \| Commodity Contract \| Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(386)	(3,226)	(673)	6,788
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	525	(2,452)	1,451	(266)
Cash Flow Hedging \| Commodity Contract \| Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	430	3,287	659	6,939
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0	0
Cash Flow Hedging \| Commodity Contract \| Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Reclassified Gain/(Loss) from AOCI into Income (Effective Portion)	(44)	(61)	14	(151)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 0	$ 0	$ 0	$ 0

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Assets	$ 297,160	$ 275,412	$ 297,160	$ 275,412	$ 296,142
Gas price derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Assets	11,159	11,515	11,159	11,515	$ 8,843
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(665)	2,201	(1,357)	2,835
Not Designated as Hedging Instrument \| Sales Revenue, Net
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	26	0	143	0
Not Designated as Hedging Instrument \| Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (691)	$ 2,201	$ (1,500)	$ 2,835

Fair Value Measurements: Schedule of Fair Values (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 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	$ (1,207)	$ (5,995)	$ (5,325)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,568)	(11,144)	(14,427)
Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
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	(977)	(3,262)	(4,175)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,568)	(11,144)	(14,427)
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	(230)	(2,733)	(1,150)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0	0
Estimate of Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	1,185	4,360	4,256
Derivative Liabilities, Total	807	2,733	29,086
Estimate of Fair Value Measurement \| Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities, Fair Value Disclosure		90	28,558
Estimate of Fair Value Measurement \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	645	4,207	2,658
Derivative Liabilities, Fair Value Disclosure	763	1,057	300
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	540	153	1,598
Derivative Liabilities, Fair Value Disclosure	44	1,586	228
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 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	2,392	10,355	9,581
Derivative Liabilities, Total	12,375	13,877	43,513
Fair Value, Inputs, Level 2 \| Interest Rate Swap
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities, Fair Value Disclosure		90	28,558
Fair Value, Inputs, Level 2 \| Utilities Group
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	1,622	7,469	6,833
Derivative Liabilities, Fair Value Disclosure	12,331	12,201	14,727
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	770	2,886	2,748
Derivative Liabilities, Fair Value Disclosure	44	1,586	228
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 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

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 579	$ 1,285	$ 2,630
Derivative Liability, Fair Value, Net	199	1,418	28,828
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	606	3,075	1,626
Derivative Liability, Fair Value, Net	608	1,315	258
Commodity Contract \| Designated as Hedging Instrument \| Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	548	1,161	2,549
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	31	124	81
Derivative Asset, Fair Value, Gross Liability	0	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	167	1,090	44
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	32	238	226
Commodity Contract \| Not Designated as Hedging Instrument \| Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	600	2,977	1,481
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	6	98	145
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	552	1,279	254
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	$ 56	36	4
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	$ 28,558

Fair Value of Financial Instruments: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 11,590	$ 13,580	$ 61,859	$ 440,861
Restricted cash and equivalents	2,534	2,274	1,975
Notes payable	107,975	96,600	75,000
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	11,590	13,580	61,859
Restricted cash and equivalents	2,534	2,274	1,975
Notes payable	107,975	96,600	75,000
Long-term debt, including current maturities	3,166,045	3,216,932	3,152,090
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, Fair Value	11,590	13,580	61,859
Restricted Cash Fair Value Disclosure	2,534	2,274	1,975
Notes payable, Fair Value	107,975	96,600	75,000
Long-term debt, including current maturities, Fair Value	$ 3,377,891	$ 3,351,305	$ 3,427,587

Other Comprehensive Income (Loss): Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ 35,098	$ 34,609	$ 70,194	$ 66,683
Revenue	347,978	325,441	901,981	775,400
Fuel, purchased power and cost of natural gas sold	98,164	84,489	317,941	256,345
Operations and maintenance	117,374	112,541	239,504	219,603
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	35,713	3,592	149,214	47,894
Income tax benefit (expense)	(10,402)	(309)	(43,757)	(4,561)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	25,311	3,283	105,457	43,333
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	(458)	1,219	(1,027)	2,643
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(327)	2,386	(842)	5,098
Income tax benefit (expense)	106	(882)	281	(1,884)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	(221)	1,504	(561)	3,214
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges \| Interest Rate Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(713)	(840)	(1,515)	(1,690)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges \| Commodity Contract
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Revenue	430	3,287	659	6,939
Fuel, purchased power and cost of natural gas sold	(44)	(61)	14	(151)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	49	55	97	110
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Operations and maintenance	(414)	(494)	(828)	(989)
Reclassification Out Of Accumulated Other Comprehensive Income \| Accumulated Defined Benefit Plans Adjustment
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	(365)	(439)	(731)	(879)
Income tax benefit (expense)	128	154	265	308
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (237)	$ (285)	$ (466)	$ (571)

Other Comprehensive Income (Loss): Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 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	(32,941)	(31,764)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Interest Rate Swap
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	0	(19,898)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(17,124)	(19,141)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Interest Rate Swap \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	985	1,098
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Commodity Contract
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	915	(168)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	258	2,586
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent \| Commodity Contract \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(424)	(4,312)
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	(16,075)	(15,209)
Accumulated Defined Benefit Plans Adjustment \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	466	571
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	915	(20,066)
AOCI Attributable to Parent \| Reclassification Out Of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 1,027	$ (2,643)

Supplemental Disclosure of Cash Flow Information: (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 37,601	$ 52,917
Supplemental Cash Flow Elements [Abstract]
Interest (net of amounts capitalized)	(65,820)	(48,139)
Income taxes, net	$ 1	$ (1,162)

Employee Benefit Plans: (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
Employee Benefit Plans: (Details) - USD ($) $ in Thousands	Jul. 24, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Defined Benefit Pension Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		$ 1,759	$ 2,078	$ 3,517	$ 4,156
Interest Cost		3,880	3,936	7,760	7,872
Expected return on plan assets		(6,129)	(5,766)	(12,258)	(11,531)
Prior service cost (benefit)		15	15	29	30
Net loss (gain)		1,001	1,793	2,003	3,586
Net periodic benefit cost		526	2,056	1,051	4,113
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer		0		0
Estimated Future Employer Contributions in Current Fiscal Year				12,700
Estimated Future Employer Contributions in Next Fiscal Year				12,700
Defined Benefit Postretirement Healthcare Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		575	467	1,150	934
Interest Cost		534	485	1,067	970
Expected return on plan assets		(79)	(70)	(158)	(140)
Prior service cost (benefit)		(109)	(107)	(218)	(214)
Net loss (gain)		125	84	250	168
Net periodic benefit cost		1,046	859	2,091	1,718
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer		1,270		2,540
Estimated Future Employer Contributions in Current Fiscal Year				2,540
Estimated Future Employer Contributions in Next Fiscal Year				5,115
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		609	878	1,436	907
Interest Cost		319	315	638	629
Prior service cost (benefit)		0	1	1	1
Net loss (gain)		250	207	500	414
Net periodic benefit cost		1,178	$ 1,401	2,575	$ 1,951
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer		$ 396		792
Estimated Future Employer Contributions in Current Fiscal Year				792
Estimated Future Employer Contributions in Next Fiscal Year				$ 1,682
Subsequent Event \| Defined Benefit Pension Plans
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions by Employer	$ 13,000

Commitments and Contingencies: Dividend Restrictions (Details) $ in Millions	Jun. 30, 2017 USD ($)
Utilities Group
Related Party Transaction [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Impairment of Assets: (Details)	3 Months Ended	6 Months Ended		12 Months Ended
Impairment of Assets: (Details)	Jun. 30, 2016 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2017 $ / MMcf $ / bbl	Jun. 30, 2016 $ / MMcf $ / bbl
Impairment of Oil and Gas Properties		$ 0	$ 39,993,000
Oil and Gas
Average Natural Gas Price Per MCF, NYMEX \| $ / MMcf				3.01	2.24
Average Natural Gas Price Per MCF, Wellhead \| $ / MMcf				2.70	1.01
Average Crude Oil Price, Per Barrel, NYMEX \| $ / bbl				48.95	43.12
Average Crude Oil Price Per Barrel, Wellhead \| $ / bbl				44.42	37.19
Impairment of Oil and Gas Properties	$ 11,000,000	$ 0	25,000,000
Oil and Gas \| Assets Not Expected To Be Utilized In Cost Of Service Gas Program
Results of Operations, Impairment of Oil and Gas Properties			$ 14,000,000

Income Taxes: (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
Income Taxes: (Details) - USD ($) $ in Millions	Jun. 30, 2017	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2017	Jun. 30, 2016
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Federal statutory rate	35.00%	35.00%		35.00%	35.00%
State income tax (net of federal tax effect)	(0.10%)	16.90%		1.00%	3.80%
Percentage depletion in excess of cost	(1.20%)	(5.90%)		(0.60%)	(13.50%)
Accounting for uncertain tax positions adjustment	0.00%	1.90%		0.00%	(10.40%)
Noncontrolling interest	(3.10%)	(25.10%)		(1.60%)	(1.90%)
IRC 172(f) carryback claim				(1.30%)	0.00%
Tax credits	(3.60%)	(0.00%)		(1.80%)	(0.00%)
Effective tax rate adjustment	4.40%	1.70%		(0.80%)	(3.50%)
Flow-through adjustments	(2.60%)	(10.60%)		(1.00%)	(1.70%)
Transaction costs				0.00%	2.30%
Effective Income Tax Rate Reconciliation Allowance For Other Funds Used During Construction, Equity	(0.60%)	(5.80%)
Other tax differences	0.90%	0.50%		0.40%	(0.60%)
Effective Tax Rate	29.10%	8.60%		29.30%	9.50%
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage		49.90%			49.90%
IRS Settlement [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities			$ 35.0
Income Tax Examination, Increase (Decrease) In Accrued Interest		$ 5.1			$ 5.1
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 8.0			$ 8.0

Accrued Liabilities: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016
Payables and Accruals [Abstract]
Accrued employee compensation, benefits and withholdings	$ 45,767	$ 56,926	$ 45,991
Accrued property taxes	34,683	40,004	33,295
Customer deposits and prepayments	41,067	51,628	44,200
Accrued interest and contract adjustment payments	33,914	45,503	42,330
CIAC current portion	1,575	0	20,211
Other (none of which is individually significant)	44,987	49,973	32,223
Total accrued liabilities	$ 201,993	$ 244,034	$ 218,250