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December 31, 2015

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Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	0001130464
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Current Fiscal Year End Date	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,384,259
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 3,248,873,889

Consolidated Statements of Income (Loss) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue:
Revenue	$ 1,572,974	$ 1,304,605	$ 1,393,570
Operating expenses:
Fuel, purchased power and cost of natural gas sold	499,132	456,887	581,782
Operations and maintenance	456,399	361,109	359,095
Depreciation, depletion and amortization	189,043	155,370	144,745
Impairment of long-lived assets	106,957	249,608	0
Taxes - property, production and severance	48,522	44,353	43,580
Other operating expenses	50,335	7,483	500
Total operating expenses	1,350,388	1,274,810	1,129,702
Operating income	222,586	29,795	263,868
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(139,590)	(86,278)	(73,017)
Allowance for funds used during construction - borrowed	2,981	1,250	1,075
Capitalized interest	1,197	1,309	982
Interest income	1,429	1,621	1,925
Allowance for funds used during construction - equity	3,270	897	994
Other expense	(609)	(372)	(377)
Other income	1,842	2,256	2,065
Total other income (expense)	(129,480)	(79,317)	(66,353)
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes	93,106	(49,522)	197,515
Equity in earnings (loss) of unconsolidated subsidiaries	0	(344)	(1)
Impairment of equity investments	0	(4,405)	0
Income tax benefit (expense)	(10,475)	22,160	(66,625)
Net income (loss)	82,631	(32,111)	130,889
Net income attributable to noncontrolling interest	(9,661)	0	0
Net income (loss) available for common stock	$ 72,970	$ (32,111)	$ 130,889
Earnings (loss) per share of common stock:
Earnings (loss) per share, Basic (usd per share)	$ 1.41	$ (0.71)	$ 2.95
Earnings (loss) per share, Diluted (usd per share)	$ 1.37	$ (0.71)	$ 2.93
Weighted average common shares outstanding:
Basic (in shares)	51,922	45,288	44,394
Diluted (in shares)	53,271	45,288	44,598

Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income (loss)	$ 82,631	$ (32,111)	$ 130,889
Other comprehensive income (loss), net of tax:
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax	(1,738)	2,657	(10,590)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost (Credit) Arising During Period, Net of Tax	(247)	0	237
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), Net of Tax	1,378	1,850	646
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Net of Tax	(154)	(150)	(141)
Other comprehensive income (loss), net of tax	(25,828)	5,989	2,378
Comprehensive income (loss)	56,803	(26,122)	133,267
Net Income (Loss) Attributable to Noncontrolling Interest	(9,661)	0	0
Comprehensive income (loss) available for common stock	47,142	(26,122)	133,267
Interest Rate Swap
Other comprehensive income (loss), net of tax:
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(20,302)	2,290	(350)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2,534	2,299	2,313
Commodity Contract
Other comprehensive income (loss), net of tax:
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(361)	5,884	9,256
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ (6,938)	$ (8,841)	$ 1,007

Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Benefit plan liability adjustments - net gain (loss), Tax	$ 757	$ (1,375)	$ 5,004
Benefit plan liability adjustments - prior service (costs), Tax	107	0	(17)
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(600)	(972)	(348)
Reclassification adjustment of benefit plan liability - prior service cost, tax	67	88	76
Interest Rate Swap
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax	10,920	(598)	186
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	(1,365)	(1,348)	(1,356)
Commodity Contract
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax	212	(3,898)	(5,425)
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	$ 4,067	$ 5,619	$ (988)

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 13,580	$ 440,861
Restricted cash and equivalents	2,274	1,697
Accounts receivable, net	263,289	147,486
Materials, supplies and fuel	107,210	86,943
Derivative assets, current	4,138	0
Income tax receivable, net	0	368
Regulatory assets, current	49,260	57,359
Other current assets	27,063	71,763
Total current assets	466,814	806,477
Investments	12,561	11,985
Property, plant and equipment	6,412,223	4,976,778
Less accumulated depreciation and depletion	(1,943,234)	(1,717,684)
Total property, plant and equipment, net	4,468,989	3,259,094
Other assets:
Goodwill	1,299,454	359,759
Intangible assets, net	8,392	3,380
Derivative assets, non-current	222	3,441
Regulatory assets, non-current	246,882	175,125
Other assets, non-current	12,130	7,382
Total other assets, non-current	1,567,080	549,087
TOTAL ASSETS	6,515,444	4,626,643
Current liabilities:
Accounts payable	153,477	89,794
Accrued liabilities	244,034	232,061
Derivative liabilities, current	2,459	2,835
Accrued income tax, net	12,552	0
Regulatory liabilities, current	13,067	4,865
Notes payable	96,600	76,800
Current maturities of long-term debt	5,743	0
Total current liabilities	527,932	406,355
Long-term debt, net of current maturities	3,211,189	1,853,682
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	535,606	450,579
Derivative liabilities, non-current	274	156
Regulatory liabilities, non-current	193,689	148,176
Benefit plan liabilities	173,682	146,459
Other deferred credits and other liabilities	138,643	155,369
Total deferred credits and other liabilities	1,041,894	900,739
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)
Redeemable noncontrolling interest	4,295	0
Stockholders’ equity -
Common stock $1 par value; 100,000,000 shares authorized; issued: 53,397,467 and 51,231,861 shares, respectively	53,397	51,232
Additional paid-in capital	1,138,982	953,044
Retained earnings	457,934	472,534
Treasury stock at cost - 15,258 and 39,720 shares, respectively	(791)	(1,888)
Accumulated other comprehensive income (loss)	(34,883)	(9,055)
Total stockholders’ equity	1,614,639	1,465,867
Noncontrolling interest	115,495	0
Total equity	1,730,134	1,465,867
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$ 6,515,444	$ 4,626,643

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1.00	$ 1.00
Treasury Stock, Shares	15,258	39,720
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	53,397,467	51,231,861

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net income (loss)	$ 82,631	$ (32,111)	$ 130,889
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	189,043	155,370	144,745
Deferred financing cost amortization	6,180	6,364	2,127
Impairment of long-lived assets and equity method investments	106,957	254,013	0
Stock compensation	10,885	4,076	9,329
Deferred income taxes	36,217	(26,028)	70,232
Employee benefit plans	14,291	20,616	14,814
Other adjustments, net	(5,518)	(4,872)	14,415
Change in certain operating assets and liabilities:
Materials, supplies and fuel	1,099	7,197	(4,563)
Accounts receivable, unbilled revenues and other current assets	(28,414)	40,125	(18,684)
Accounts payable and other current liabilities	(40,195)	(4,779)	7,887
Regulatory assets	3,614	21,883	(38,774)
Regulatory liabilities	(14,082)	1,675	(7,633)
Contributions to defined benefit pension plans	(14,200)	(10,200)	(10,200)
Interest rate swap settlement	(28,820)	0	0
Other operating activities, net	775	(9,034)	733
Net cash provided by operating activities	320,463	424,295	315,317
Investing activities:
Property, plant and equipment additions	(474,783)	(455,481)	(398,494)
Acquisition of net assets, net of long-term debt assumed	(1,124,238)	(21,970)	0
Proceeds from sale of assets	11,418	0	0
Other investing activities	(1,139)	1,062	(2,653)
Net cash provided by (used in) investing activities	(1,588,742)	(476,389)	(401,147)
Financing activities:
Dividends paid on common stock	(87,570)	(72,604)	(69,636)
Common stock issued	121,619	248,759	3,251
Short-term borrowings - issuances	425,400	397,310	396,250
Short-term borrowings - repayments	(405,600)	(395,510)	(403,750)
Long-term debt - issuance	1,767,608	300,000	160,000
Long-term debt - repayments	(1,164,308)	(275,000)	(12,200)
Sale of noncontrolling interest	216,370	0	0
Distributions to noncontrolling interests	(9,561)	0	0
Equity units - issuance	0	290,030	0
Other financing activities	(22,960)	(9,283)	17,152
Net cash provided by (used in) financing activities	840,998	483,702	91,067
Net change in cash and cash equivalents	(427,281)	431,608	5,237
Cash and cash equivalents:
Cash and cash equivalents beginning of year	440,861	9,253	4,016
Cash and cash equivalents end of year	$ 13,580	$ 440,861	$ 9,253

Consolidated Statement Of Equity - USD ($) $ in Thousands	Total	Common Stock	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest [Member]
Total equity at Dec. 31, 2013	$ 1,283,500	$ 44,550	$ (1,968)	$ 742,344	$ 515,996	$ (17,422)	$ 0
Common Stock, Shares, Outstanding at Dec. 31, 2013		44,550,239
Treasury Stock, Shares at Dec. 31, 2013			50,877
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	130,889				130,889
Net income attributable to noncontrolling interest	0
Net income (loss)	130,889
Other comprehensive income (loss), net of tax	2,378					2,378
Dividends on common stock	(69,636)				(69,636)
Share-based compensation	4,415	$ 112	$ 93	4,210
Share-based compensation, Shares		111,507	(8,651)
Tax effect of share-based compensation	(499)			(499)
Dividend reinvestment and stock purchase plan	2,878	$ 52		2,826
Dividend reinvestment and stock purchase plan, shares issued		52,326
Other stock transactions	(41)			(41)
Total equity at Dec. 31, 2014	$ 1,353,884	$ 44,714	$ (1,875)	748,840	577,249	(15,044)	0
Common Stock, Shares, Outstanding at Dec. 31, 2014		44,714,072
Treasury Stock, Shares at Dec. 31, 2014			42,226
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.56
Net income (loss) available for common stock	$ (32,111)				(32,111)
Net income attributable to noncontrolling interest	0
Net income (loss)	(32,111)
Other comprehensive income (loss), net of tax	5,989					5,989
Dividends on common stock	(72,604)				(72,604)
Share-based compensation	4,240	$ 127	$ (13)	4,126
Share-based compensation, Shares		126,765	(2,506)
Issuance of common stock	254,581	$ 6,325		248,256
Issuance of common stock, shares		6,325,000
Issuance costs	(17,926)			(17,926)
Premium on Equity Units	(33,118)			(33,118)
Dividend reinvestment and stock purchase plan	2,957	$ 66		2,891
Dividend reinvestment and stock purchase plan, shares issued		66,024
Other stock transactions	(25)			(25)
Total equity at Dec. 31, 2015	$ 1,465,867	$ 51,232	$ (1,888)	953,044	472,534	(9,055)	0
Common Stock, Shares, Outstanding at Dec. 31, 2015		51,231,861
Treasury Stock, Shares at Dec. 31, 2015	39,720		39,720
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.62
Net income (loss) available for common stock	$ 72,970				72,970
Net income attributable to noncontrolling interest	(9,661)						9,661
Net income (loss)	82,631
Other comprehensive income (loss), net of tax	(25,828)					(25,828)
Dividends on common stock	(87,570)				(87,570)
Share-based compensation	5,479	$ 146	$ 668	4,665
Share-based compensation, Shares		145,634	(16,165)
Issuance of common stock	119,990	$ 1,969		118,021
Issuance of common stock, shares		1,968,738
Issuance costs	(1,566)			(1,566)
Dividend reinvestment and stock purchase plan	2,983	$ 50		2,933
Dividend reinvestment and stock purchase plan, shares issued		51,234
Other stock transactions	476		$ 429	47
Other stock transactions, shares			(8,297)
Sale of noncontrolling interest	177,233			61,838			115,395
Distributions to noncontrolling interest	(9,561)						(9,561)
Total equity at Dec. 31, 2016	$ 1,730,134	$ 53,397	$ (791)	$ 1,138,982	$ 457,934	$ (34,883)	$ 115,495
Common Stock, Shares, Outstanding at Dec. 31, 2016		53,397,467
Treasury Stock, Shares at Dec. 31, 2016	15,258		15,258
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.68

Business Description And Significant Accounting Policies:

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business Description and Significant Accounting Policies

BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining, and Oil and Gas.

Segment Reporting

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska.

All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program.

For further descriptions of our reportable business segments, see Note 5.

The following changes have been made to our Consolidated Statements of Income (Loss) to reflect combined revenue and combined operations and maintenance expenses, rather than by business group as previously reported, for the twelve months ended December 31, 2015 and December 31, 2014 respectively:



	Year Ended December 31, 2015							Year Ended December 31, 2014
(in thousands)	As Previously Reported		Presentation Reclassification			As Currently Reported		As Previously Reported		Presentation Reclassification			As Currently Reported
Revenue:
Utilities	$	1,219,526	$	(1,219,526	)	$	—	$	1,300,969	$	(1,300,969	)	$	—
Non-regulated energy	$	85,079	$	(85,079	)	$	—	$	92,601	$	(92,601	)	$	—
Revenue	$	—	$	1,304,605		$	1,304,605	$	—	$	1,393,570		$	1,393,570

Operating Expenses:
Utilities - operations and maintenance	$	272,407	$	(272,407	)	$	—	$	270,954	$	(270,954	)	$	—
Non-regulated energy operations and maintenance	$	88,702	$	(88,702	)	$	—	$	88,141	$	(88,141	)	$	—
Operations and maintenance	$	—	$	361,109		$	361,109	$	—	$	359,095		$	359,095

This presentation reclassification did not impact our consolidated financial position, results of operations or cash flows.

Segment Reporting Transition of Cheyenne Light’s Natural Gas Distribution

Effective January 1, 2016, the natural gas operations of Cheyenne Light have been included in our Gas Utilities Segment. Through December 31, 2015, Cheyenne Light’s natural gas operations were included in our Electric Utilities Segment as these natural gas operations were consolidated within Cheyenne Light since its acquisition. This change is a result of our business segment reorganization to, among other things, integrate all regulated natural gas operations, including the SourceGas Acquisition, into our Gas Utilities Segment which is led by the Group Vice President, Natural Gas Utilities. Likewise, all regulated electric utility operations, including Cheyenne Light’s electric utility operations, are reported in our Electric Utilities Segment, which is led by the Group Vice President, Electric Utilities. The prior periods have been reclassified to reflect this change in presentation between the Electric Utilities and Gas Utilities segments. See Note 5 for Revenues and Net Income amounts reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015 and December 31, 2014; and Segment Assets reclassified from the Electric Utilities segment to the Gas Utilities segment for the twelve months ended December 31, 2015. This segment reclassification did not impact our consolidated financial position, results of operations or cash flows.

Revisions

Certain revisions have been made to prior years’ financial information to conform to the current year presentation.

The Company revised its presentation of cash and book overdrafts. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million, $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the consolidated balance sheet as of December 31, 2015 and to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 5.

Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information.

Variable Interest Entities

We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIEs most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

Our evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Equivalents

We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining, Oil and Gas, and Power Generation business segments consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.

We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

Following is a summary of accounts receivable as of December 31 (in thousands):



2016	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	41,730	$	36,463	$	(353	)	$	77,840
Gas Utilities	88,168		88,329		(2,026		)	174,471
Power Generation	1,420		—		—			1,420
Mining	3,352		—		—			3,352
Oil and Gas	3,991		—		(13		)	3,978
Corporate	2,228		—		—			2,228
Total	$	140,889	$	124,792	$	(2,392	)	$	263,289



2015	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities ^(a)	$	41,679	$	35,874	$	(727	)	$	76,826
Gas Utilities ^(a)	30,330		32,869		(1,001		)	62,198
Power Generation	1,187		—		—			1,187
Mining	2,760		—		—			2,760
Oil and Gas	3,502		—		(13		)	3,489
Corporate	1,026		—		—			1,026
Total	$	80,484	$	68,743	$	(1,741	)	$	147,486

________________

(a)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015, previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment.

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue).

Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement.

Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):



	December 31, 2016		December 31, 2015
Materials and supplies	$	68,456	$	55,726
Fuel - Electric Utilities	3,667		5,567
Natural gas in storage	35,087		25,650
Total materials, supplies and fuel	$	107,210	$	86,943

Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands):



	December 31, 2016		December 31, 2015
Accrued employee compensation, benefits and withholdings	$	56,926	$	43,342
Accrued property taxes	40,004		32,393
Accrued payments related to litigation expenses and settlements	—		38,750
Customer deposits and prepayments	51,628		53,496
Accrued interest and contract adjustment payments	45,503		25,762
Other (none of which is individually significant)	49,973		38,318
Total accrued liabilities	$	244,034	$	232,061

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability.

The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.

Oil and Gas Operations

We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized.

Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length.

Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information.

The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31, 2016. See information on our oil and gas drilling activities in Note 21.

Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories.

Goodwill and Intangible Assets

Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives.

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements.

We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information.

Goodwill at our Electric utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million, or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million, or 28% of the transaction, to the Gas Utilities.

We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands):



	Electric Utilities ^(a)		Gas Utilities ^(a)		Power Generation		Total
Ending balance at December 31, 2014	$	248,479	$	96,152	$	8,765	$	353,396
Additions ^(b)	—		6,363		—		6,363
Ending balance at December 31, 2015	$	248,479	$	102,515	$	8,765	$	359,759
Additions ^(c)	—		939,695		—		939,695
Ending balance at December 31, 2016	$	248,479	$	1,042,210	$	8,765	$	1,299,454

_________________


(a)	Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details.


(b)	Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc.


(c)	Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

Our intangible assets represent easements, rights-of-way, customer listings, and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized from 2 years up to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):



	2016			2015			2014
Intangible assets, net, beginning balance	$	3,380		$	3,176		$	3,397
Additions	5,522			434			—
Amortization expense ^(a)	(510		)	(230		)	(221		)
Intangible assets, net, ending balance	$	8,392		$	3,380		$	3,176

_________________


(a)	Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.

Asset Retirement Obligations

Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability.

We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 8.

Fair Value Measurements

Derivative Financial Instruments

Assets and liabilities are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:


•	The commodity contracts for the Oil and Gas segment are valued under the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.

Electric Utilities and Gas Utilities Segments:

•

The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchanged-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market data where market data for pricing is observable. In addition, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Corporate Segment:

•

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. Our remaining interest rate swap as of December 31, 2016 expired in January 2017.

Additional information is included in Note 10.

Derivatives and Hedging Activities

The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, or if they qualify for certain exemptions, including the normal purchases and normal sales exemption. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists.

Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.

Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the estimated useful life of the related debt.

Development Costs

According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income (Loss).

Legal Costs

Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred.

When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.

Regulatory Accounting

Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.

We had the following regulatory assets and liabilities (in thousands):



	Maximum
	Amortization	As of		As of
	(in years)	December 31, 2016		December 31, 2015
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	17,491	$	24,751
Deferred gas cost adjustments^(a)(d)	1	15,329		15,521
Gas price derivatives ^(a)	4	8,843		23,583
Deferred taxes on AFUDC^(b)	45	15,227		12,870
Employee benefit plans ^{(c) (e)}	12	108,556		83,986
Environmental^(a)	subject to approval	1,108		1,180
Asset retirement obligations^(a)	44	505		457
Loss on reacquired debt ^(a)	22	20,188		3,133
Renewable energy standard adjustment ^(a)	5	1,605		5,068
Deferred taxes on flow through accounting^(c)	35	37,498		29,722
Decommissioning costs ^(b)	10	16,859		18,310
Gas supply contract termination ^(a)	5	26,666		—
Other regulatory assets^(a)	15	26,267		13,903
		$	296,142	$	232,484

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	10,368	$	7,814
Employee benefit plans^(c)	12	68,654		47,218
Cost of removal^(a)	44	118,410		90,045
Other regulatory liabilities^(c)	25	9,324		7,964
		$	206,756	$	153,041

__________


(a)	Recovery of costs, but we are not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d)

Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.


(e)	Increase compared to 2015 was driven by the addition of the SourceGas employee benefit plans.

Regulatory assets represent items we expect to recover from customers through probable future rates.

Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission.

Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions.

Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. The 4-year term represents the maximum forward term hedged.

Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plans and post-retirement benefit plans in regulatory assets rather than in AOCI, including costs being amortized from the Aquila Transaction.

Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown.

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details.

Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills.

Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes.

Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. South Dakota Electric is allowed a return on their costs, in addition to recovery of those costs.

Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, and exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements are not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016.

Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.

Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.

Employee Benefit Plans - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement aspect of a rate regulated environment.

Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that generated the credit.

We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss).

We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.

Earnings per Share of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, and outstanding stock options, restricted stock and performance shares under our equity compensation plans.

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):



	December 31, 2016		December 31, 2015			December 31, 2014

Net income (loss) available for common stock	$	72,970	$	(32,111	)	$	130,889

Weighted average shares - basic	51,922		45,288			44,394
Dilutive effect of:
Equity Units	1,222		—			—
Equity compensation	127		—			204
Weighted average shares - diluted	53,271		45,288			44,598

Net income (loss) available for common stock, per share - Diluted	$	1.37	$	(0.71	)	$	2.93

Due to our Net loss available for common stock for the year ended December 31, 2015, potentially diluted securities were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 83,000 equity compensation shares were excluded from the computation for the year ended December 31, 2015.

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	December 31, 2016	December 31, 2015	December 31, 2014

Equity compensation	3	112	81
Equity units	—	6,440	—
Anti-dilutive shares excluded from computation of earnings (loss) per share	3	6,552	81

Business Combinations

We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for the SourceGas Acquisition.

Noncontrolling Interest

We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests.

Share-Based Compensation

We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.

Recently Issued and Adopted Accounting Standards

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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows.

Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16

In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.

Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07

On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

Acquisition:

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisition

ACQUISITION

Acquisition of SourceGas

On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016. SourceGas is a 99.5% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado.

Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility.

In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million and $10 million for the years ending December 31, 2016 and 2015, respectively. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses and Interest expense on the Consolidated Statements of Income (Loss).

Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income (loss) of $15 million, attributable to SourceGas for the period from February 12 through December 31, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers.

We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values.

The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year from the acquisition date to finalize the purchase price allocation. From the time of acquisition through December 31, 2016, we decreased goodwill by $6.7 million, reflecting the working capital adjustment received of $11 million and changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.



	(in thousands)
Purchase Price	$	1,894,882
Less: Long-term debt assumed	(760,000		)
Less: Working capital adjustment received	(10,644		)
Consideration Paid, net of working capital adjustment received	$	1,124,238

Allocation of Purchase Price:
Current Assets	$	112,983
Property, plant & equipment, net	1,058,093
Goodwill	939,695
Deferred charges and other assets, excluding goodwill	133,299
Current liabilities	(172,454		)
Long-term debt	(758,874		)
Deferred credits and other liabilities	(188,504		)
Total consideration paid, net of working-capital adjustment received	$	1,124,238

Conditions of SourceGas Acquisition Regulatory Approval

The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below:

The APSC order includes a twelve-month base rate moratorium, an annual $0.25 million customer credit for a term of up to five years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The CPUC order includes a two-year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three-year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five-years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements.

The NPSC order includes a three-year base rate moratorium, a three-year continuation of the Choice Gas Program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements.

The WPSC order includes a three-year continuation of the Choice Gas Program, as well as various other terms and reporting requirements.

All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska. However, Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs.

Settlement of Gas Supply Contract

On April 29, 2016, we settled for $40 million, a former SourceGas contract that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities in the purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of the net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five-year period.

Pro Forma Results (unaudited)

We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:



	Pro Forma Results
	December 31,
	2016		2015
	(in thousands, except per share amounts)
Revenue	$	1,651,936	$	1,763,901
Net income (loss) available for common stock	$	112,878	$	(13,369	)
Earnings (loss) per share, Basic	$	2.17	$	(0.26	)
Earnings (loss) per share, Diluted	$	2.12	$	(0.26	)

We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2015, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%.

These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future.

Seller’s noncontrolling interest

One of the sellers retained 0.5% of the outstanding equity interests of SourceGas under the terms of the purchase agreement. As part of the transaction, we entered into an associated option agreement with that holder of the retained interest. The terms of this agreement provide us a call option to purchase the remaining interest beginning 366 days after the initial close of the SourceGas Transaction. If we choose not to exercise this option during a ninety-day period, the seller may exercise the put option to sell us the retained interest. The value of this 0.5% equity interest is shown as Redeemable noncontrolling interest on the accompanying consolidated balance sheets.

- 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
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=73530397&loc=SL65897772-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
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-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
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-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Property, Plant And Equipment:

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):



	2016			2015			Lives (in years)
Electric Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	1,303,101	41	$	1,136,847	43	30	63
Electric transmission	354,801		52	280,257		50	40	70
Electric distribution	712,575		48	699,775		47	15	75
Plant acquisition adjustment ^(a)	4,870		32	4,870		32	32	32
General	164,761		25	159,496		24	3	65
Capital lease - plant in service ^(b)	261,441		20	261,441		20	20	20
Total electric plant in service	2,801,549			2,542,686
Construction work in progress	74,045			96,501
Total electric plant	2,875,594			2,639,187
Less accumulated depreciation and amortization	578,162			526,954
Electric plant net of accumulated depreciation and amortization ^(c)	$	2,297,432		$	2,112,233

_____________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 14 years remaining.


(b)	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.


(c)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.



	2016			2015			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	10,821	35	$	13	30	17	71
Gas transmission	338,729		48	45,104		60	22	70
Gas distribution	1,303,366		42	692,800		45	33	47
Cushion gas - depreciable ^(a)	3,539		28	—		0	28	28
Cushion gas - not depreciated ^(a)	47,055		0	—		0	0	0
Storage	27,686		31	—		0	15	48
General	339,382		19	122,109		22	3	44
Total gas plant in service	2,070,578			860,026
Construction work in progress	28,446			11,854
Total gas plant	2,099,024			871,880
Less accumulated depreciation and amortization	194,585			120,458
Gas plant net of accumulated depreciation and amortization ^(b)	$	1,904,439		$	751,422

_____________


(a)	Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.



2016											Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	161,430	$	1,298	$	162,728	$	55,157	$	107,571	33	2	40
Mining	151,709		4,642		156,351		105,219		51,132		13	2	59
Oil and Gas ^(a)	1,101,106		—		1,101,106		1,016,226		84,880		25	2	25

_____________


(a)	Net Property, Plant and Equipment includes full cost pool net assets of approximately $43 million.



2015											Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	156,721	$	2,182	$	158,903	$	51,471	$	107,432	33	2	40
Mining	154,630		3,649		158,279		97,663		60,616		13	2	59
Oil and Gas	1,132,776		—		1,132,776		925,908		206,868		24	3	25



2016												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	5,446	$	11,974	$	17,420	$	(6,115	)	$	23,535	8	3	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.



2015												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	376	$	15,377	$	15,753	$	(4,770	)	$	20,523	10	5	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.

Jointly Owned Facilities:

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Jointly Owned Facilities

JOINTLY OWNED FACILITIES

Utility Plant

Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.

•

South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

•

South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.

•

South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant.


•	Colorado Electric owns 50% of the Busch Ranch Wind Farm while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm for the life of the facility. We retain responsibility for operations of the wind farm.

Non-Regulated Plants

Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income (Loss). Each of the respective owners is responsible for providing its own financing.


•	Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. We retain responsibility for plant operations.

At December 31, 2016, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	113,611	$	256	$	55,878
Transmission Tie	$	19,978	$	13	$	5,793
Wygen I	$	109,412	$	957	$	37,156
Wygen III	$	138,261	$	1,806	$	17,635
Busch Ranch Wind Farm	$	18,899	$	—	$	3,102

Business Segments Information:

12 Months Ended

Dec. 31, 2016

Segment Reporting Information, Additional Information [Abstract]

Business Segments Information

BUSINESS SEGMENTS INFORMATION

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of December 31,	2016		2015
Electric ^{(a) (d)}	$	2,859,559	$	2,704,330
Gas ^{(b) (d)}	3,307,967		999,778
Power Generation^(a)	73,445		60,864
Mining	67,347		76,358
Oil and Gas	96,435		208,956
Corporate ^(c)	110,691		576,357
Total assets	$	6,515,444	$	4,626,643

__________________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


(b)	Includes the assets acquired in the SourceGas acquisition on February 12, 2016.


(c)	Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition.


(d)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million, previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment.



Capital Expenditures and Asset Acquisitions ^(a) for the years ended December 31,	2016		2015
Capital Expenditures
Electric Utilities ^(b)	$	258,739	$	171,897
Gas Utilities^(b)	173,930		99,674
Power Generation	4,719		2,694
Mining	5,709		5,767
Oil and Gas	6,669		168,925
Corporate	17,353		9,864
Total Capital Expenditures	467,119		458,821
Asset Acquisitions
Gas Utilities^{(b) (c)}	1,124,238		21,970
Total Capital Expenditures and Asset Acquisitions	$	1,591,357	$	480,791

_________________


(a)	Includes accruals for property, plant and equipment.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.


(c)	SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2. The 2015 acquisitions represent two acquisitions made by Wyoming Gas.



Property, Plant and Equipment as of December 31,	2016		2015
Electric Utilities ^{(a) (b)}	$	2,875,594	$	2,639,187
Gas Utilities ^{(b) (c)}	2,099,024		871,880
Power Generation ^(a)	162,728		158,903
Mining	156,351		158,279
Oil and Gas	1,101,106		1,132,776
Corporate	17,420		15,753
Total property, plant and equipment	$	6,412,223	$	4,976,778

_______________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility Property, Plant and Equipment of $130 million, previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.


(c)	Includes Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016.



	Consolidating Income Statement
Year ended December 31, 2016	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	664,330		$	838,343		$	7,176		$	29,067		$	34,058		$	—		$	—		$	1,572,974
Inter-company revenue	12,951			—			83,955			31,213			—			347,500			(475,619		)	—
Total revenue	677,281			838,343			91,131			60,280			34,058			347,500			(475,619		)	1,572,974

Fuel, purchased power and cost of natural gas sold	261,349			352,165			—			—			—			456			(114,838		)	499,132
Operations and maintenance	158,134			245,826			32,636			39,576			32,158			373,773			(326,847		)	555,256
Depreciation, depletion and amortization	84,645			78,335			4,104			9,346			13,902			22,538			(23,827		)	189,043
Impairment of long-lived assets^(a)	—			—			—			—			106,957			—			—			106,957
Operating income (loss)	173,153			162,017			54,391			11,358			(118,959		)	(49,267		)	(10,107		)	222,586

Interest expense	(56,237		)	(76,586		)	(3,758		)	(401		)	(4,864		)	(109,035		)	115,469			(135,412		)
Interest income	5,946			1,573			1,983			24			—			97,147			(105,244		)	1,429
Other income (expense), net	3,193			184			2			2,209			110			179,839			(181,034		)	4,503
Income tax benefit (expense)	(40,228		)	(27,462		)	(17,129		)	(3,137		)	52,659			24,365			457			(10,475		)
Net income (loss)	85,827			59,726			35,489			10,053			(71,054		)	143,049			(180,459		)	82,631
Net income attributable to noncontrolling interest	—			(102		)	(9,559		)	—			—			—			—			(9,661		)
Net income (loss) available for common stock	$	85,827		$	59,624		$	25,930		$	10,053		$	(71,054	)	$	143,049		$	(180,459	)	$	72,970

________________


(a)	Oil and Gas includes oil and gas property impairments (see Note 13).



	Consolidating Income Statement
Year ended December 31, 2015	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	668,226		$	551,300		$	7,483		$	34,313		$	43,283		$	—		$	—		$	1,304,605
Inter-company revenue	11,617			—			83,307			30,753			—			227,708			(353,385		)	—
Total revenue	679,843			551,300			90,790			65,066			43,283			227,708			(353,385		)	1,304,605

Fuel, purchased power and cost of natural gas sold	269,409			299,645			—			—			—			122			(112,289		)	456,887
Operations and maintenance	160,924			140,723			32,140			41,630			41,593			225,721			(229,786		)	412,945
Depreciation, depletion and amortization	80,929			32,326			4,329			9,806			29,287			9,273			(10,580		)	155,370
Impairment of long-lived assets^(a)	—			—			—			—			249,608			—			—			249,608
Operating income (loss)	168,581			78,606			54,321			13,630			(277,205		)	(7,408		)	(730		)	29,795

Interest expense	(55,159		)	(17,912		)	(4,218		)	(433		)	(2,726		)	(57,839		)	54,568			(83,719		)
Interest income	4,114			601			1,015			34			217			48,582			(52,942		)	1,621
Other income (expense), net	1,216			315			71			2,247			(337		)	70,889			(71,964		)	2,437
Impairment of equity investments ^(a)	—			—			—			—			(4,405		)	—			—			(4,405		)
Income tax benefit (expense)	(41,173		)	(22,304		)	(18,539		)	(3,608		)	104,498			2,926			360			22,160
Net income (loss)	77,579			39,306			32,650			11,870			(179,958		)	57,150			(70,708		)	(32,111		)
Net income attributable to noncontrolling interest	—			—			—			—			—			—			—			—
Net income (loss) available for common stock	$	77,579		$	39,306		$	32,650		$	11,870		$	(179,958	)	$	57,150		$	(70,708	)	$	(32,111	)

________________


(a)	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).



	Consolidating Income Statement
Year ended December 31, 2014	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	643,446		$	657,523		$	6,401		$	31,086		$	55,114		$	—		$	—		$	1,393,570
Inter-company revenue	14,110			—			81,157			32,272			—			222,460			(349,999		)	—
Total revenue	657,556			657,523			87,558			63,358			55,114			222,460			(349,999		)	1,393,570

Fuel, purchased power and cost of natural gas sold	291,644			403,781			—			—			—			116			(113,759		)	581,782
Operations and maintenance	156,252			142,024			33,126			41,172			42,659			213,415			(225,473		)	403,175
Depreciation, depletion and amortization	77,011			28,912			4,540			10,276			24,246			7,690			(7,930		)	144,745
Operating income (loss)	132,649			82,806			49,892			11,910			(11,791		)	1,239			(2,837		)	263,868

Interest expense	(51,640		)	(17,487		)	(4,351		)	(493		)	(2,603		)	(50,299		)	55,913			(70,960		)
Interest income	4,590			466			682			59			918			48,969			(53,759		)	1,925
Other income (expense), net	1,074			124			(6		)	2,275			183			61,605			(62,574		)	2,681
Income tax benefit (expense)	(29,403		)	(21,758		)	(17,701		)	(3,299		)	4,768			24			744			(66,625		)
Net income (loss)	57,270			44,151			28,516			10,452			(8,525		)	61,538			(62,513		)	130,889
Net income attributable to noncontrolling interest	—			—			—			—			—			—			—			—
Net income (loss) available for common stock	$	57,270		$	44,151		$	28,516		$	10,452		$	(8,525	)	$	61,538		$	(62,513	)	$	130,889

- 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
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-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
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-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
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-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
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-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
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-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
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-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
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-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-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
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-URI http://asc.fasb.org/extlink&oid=68060357&loc=d3e8906-108599

+ Details

Long-Term Debt:

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

Long-term debt outstanding was as follows (dollars in thousands):



		Interest Rate at
	Due Date	December 31, 2016	December 31, 2016			December 31, 2015
Corporate
Senior unsecured notes due 2023	November 30, 2023	4.25%	$	525,000		$	525,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Corporate term loan due 2017 ^(a)			—			300,000
Remarketable junior subordinated notes ^(b)	November 1, 2028	3.50%	299,000			299,000
Senior unsecured notes due 2019	January 11, 2019	2.50%	250,000			—
Senior unsecured notes due 2026	January 15, 2026	3.95%	300,000			—
Senior unsecured notes due 2027	January 15, 2027	3.15%	400,000			—
Senior unsecured notes, due 2046	September 15, 2046	4.20%	300,000			—
Corporate term loan due 2019 ^(a)	August 9, 2019	1.74%	400,000			—
Corporate term loan due 2021	June 7, 2021	2.32%	24,406			—
Total Corporate Debt			2,698,406			1,324,000
Less unamortized debt discount			(4,413		)	(1,890		)
Total Corporate Debt, Net			2,693,993			1,322,110

Electric Utilities
First Mortgage Bonds due 2044	October 20, 2044	4.43%	85,000			85,000
First Mortgage Bonds due 2044	October 20, 2044	4.53%	75,000			75,000
First Mortgage Bonds due 2032	August 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%	180,000			180,000
First Mortgage Bonds due 2037	November 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021 ^(c)	September 1, 2021	0.72%	7,000			7,000
Industrial development revenue bonds due 2027 ^(c)	March 1, 2027	0.72%	10,000			10,000
Series 94A Debt, variable rate ^(c)	June 1, 2024	0.88%	2,855			2,855
Total Electric Utilities Debt			544,855			544,855
Less unamortized debt discount			(94		)	(99		)
Total Electric Utilities Debt			544,761			544,756

Total long-term debt			3,238,754			1,866,866
Less current maturities			5,743			—
Less deferred financing costs ^(d)			21,822			13,184
Long-term debt, net of current maturities and deferred financing costs			$	3,211,189		$	1,853,682

_______________


(a)	Variable interest rate, based on LIBOR plus a spread.


(b)	See Note 12 for RSN details.


(c)	Variable interest rate.


(d)	Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2016 and December 31, 2015, respectively.

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2017	$	5,743
2018	$	5,743
2019	$	655,742
2020	$	205,742
2021	$	8,436
Thereafter	$	2,361,855

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2016.

Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.

Assumption of Long-Term Debt

At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following:


•	$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017.


•	$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.


•	$340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875%.

The $760 million in long-term debt assumed in the SourceGas Acquisition was repaid in August 2016.

Debt Transactions

On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following:


•	Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;


•	Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;


•	Repay the remaining $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;


•	Pay down $100 million of the $500 million three-year unsecured term loan discussed below;


•	Payment of $29 million for the settlement of $400 million notional interest rate swap; and


•	Remainder was used for general corporate purposes.

On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility.

In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 1, on June 7, 2016, we entered into a 2.32%, $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million, the first of which was paid on June 30, 2016.

On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95%, ten-year senior notes due 2026, and $250 million of 2.50%, three-year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note.

Amortization Expense

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):



	Deferred Financing Costs Remaining at		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616
Senior unsecured notes due 2023	2,921		494		494		653
Senior unsecured notes due 2019	763		643		—		—
Senior unsecured notes due 2020	592		167		167		167
Senior unsecured notes due 2026	2,318		262		—		—
Senior unsecured notes due 2027	3,281		121		—		—
Senior unsecured notes due 2046	3,193		37		—		—
Corporate term loan due 2019	287		144		—		—
Bridge Term Loan	—		843		4,213		—
RSNs due 2028	1,449		122		10		—
First mortgage bonds due 2044 (South Dakota Electric)	663		24		24		6
First mortgage bonds due 2044 (Wyoming Electric)	613		23		22		6
First mortgage bonds due 2032	518		33		33		33
First mortgage bonds due 2039	1,734		76		76		76
First mortgage bonds due 2037	643		31		31		31
Other	506		304		43		53
Total	$	21,822	$	3,861	$	5,617	$	1,641

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2016, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2016:


•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2016, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.

Notes Payable:

12 Months Ended

Dec. 31, 2016

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2016, we were in compliance with all of these financial covenants.

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):

Revolving Credit Facility

On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one-year extension options (subject to consent from the lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250%, 1.250%, and 1.250%, respectively, at December 31, 2016. A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility.

On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of December 31, 2016.

As of December 31, 2016 and 2015, we had outstanding letters of credit totaling approximately $36 million and approximately $33 million, respectively.

Deferred financing costs on the facility of $5.4 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income (Loss). The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616

Debt Covenants

On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.70 to 1.00 for the quarter ending December 31, 2016 and subsequently for future quarters beginning March 31, 2017, maintain the ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs.

Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:

Asset Retirement Obligations:

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and Gas segment, reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our regulated utilities segments. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment.

The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	December 31, 2015		Liabilities Incurred		Liabilities Settled			Accretion		Liabilities Acquired ^(a)		Revisions to Prior Estimates^(b)(c)			December 31, 2016
Electric Utilities	$	4,462	$	—	$	—		$	191	$	—	$	8		$	4,661
Gas Utilities	136		—		—			791		22,412		6,436			29,775
Mining	18,633		—		(105		)	822		—		(6,910		)	12,440
Oil and Gas	21,504		3		(2,049		)	1,382		—		1,923			22,763
Total	$	44,735	$	3	$	(2,154	)	$	3,186	$	22,412	$	1,457		$	69,639



	December 31, 2014		Liabilities Incurred		Liabilities Settled			Accretion		Liabilities Acquired		Revisions to Prior Estimates^(c)			December 31, 2015
Electric Utilities	$	7,012	$	—	$	(2,733	)	$	183	$	—	$	—		$	4,462
Gas Utilities	291		—		(168		)	13		—		—			136
Mining	19,138		—		—			993		—		(1,498		)	18,633
Oil and Gas	20,945		828		(1,792		)	1,371		—		152			21,504
Total	$	47,386	$	828	$	(4,693	)	$	2,560	$	—	$	(1,346	)	$	44,735

_____________________


(a)	Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas.


(b)	The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.


(c)	The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. The 2015 Mining Revision to Prior Estimates reflects a change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.

We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a value for the cost of these obligations cannot be measured at this time.

Risk Management Activities:

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management Activities

RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to:


•	Commodity price risk associated with our natural long position of crude oil and natural gas reserves and production, our retail natural gas marketing activities, and our fuel procurement for certain of our gas-fired generation assets; and


•	Interest rate risk associated with our variable rate debt.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

As of December 31, 2016, our credit exposure included a $1.1 million exposure to a non-investment grade rural electric cooperative. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10.

Oil and Gas

We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions from these activities, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production. Futures contracts provide the requirement to buy or sell the commodity at a fixed price in the future. Option contracts provide the right, but not the obligation to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment based on the difference between the fixed price and the settled commodity market price on the settlement date. We elect hedge accounting on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income (Loss).

The contract or notional amounts and terms of our crude oil futures and options and natural gas futures held at our Oil and Gas segment are comprised of short positions. A short position is a contract to sell the commodity while a long position is a contract to purchase the commodity. We had the following short positions as of:



	December 31, 2016			December 31, 2015
	Crude oil futures and swaps ^(b)	Crude oil options	Natural gas futures and swaps ^(b)	Crude oil futures and swaps ^(b)	Natural gas futures and swaps ^(b)
Notional ^(a)	108,000	36,000	2,700,000	198,000	4,392,500
Maximum terms in months ^(c)	24	12	24	24	24

________________________


(a)	Crude in Bbls, gas in MMBtus.


(b)	These financial instruments were designated as cash flow hedges upon inception.


(c)	Refers to the maximum forward period hedged.

Based on December 31, 2016 market prices, a $0.9 million loss would be reclassified from AOCI during 2017. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss), or the Consolidated Statements of Comprehensive Income (Loss).

We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from January 2017 through April 2019. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:



	December 31, 2016		December 31, 2015
	Notional (MMBtus)	Maximum Term (months) ^(a)	Notional (MMBtus)	Maximum Term (months) ^(a)
Natural gas futures purchased	14,770,000	48	20,580,000	60
Natural gas options purchased, net ^(b)	3,020,000	5	2,620,000	3
Natural gas basis swaps purchased	12,250,000	48	18,150,000	60
Natural gas over-the-counter swaps, net ^(c)	4,622,302	28	—	0
Natural gas physical commitments, net ^(d)	21,504,378	10	—	0

__________


(a)	Term reflects the maximum forward period hedged.


(b)	Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions.


(c)	As of December 31, 2016, 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.


(d)	Volumes exclude contracts that qualify for normal purchase, normal sales exception.

Financing Activities

In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to fix the Treasury yield component associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten-year senior notes on August 10, 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as a component of interest expense over the ten-year life of the $400 million unsecured note issued on August 19, 2016. The ineffective portion of $1.0 million, related to the timing of the debt issuance, was recognized in earnings as a component of interest expense. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:



	December 31, 2016			December 31, 2015
	Interest Rate Swaps ^(a)			Interest Rate Swaps ^(a)			Interest Rate Swaps ^(b)
Notional	$	50,000		$	75,000		$	250,000
Weighted average fixed interest rate	4.94		%	4.97		%	2.29		%
Maximum terms in months	1			13			16
Derivative assets, non-current	$	—		$	—		$	3,441
Derivative liabilities, current	$	90		$	2,835		$	—
Derivative liabilities, non-current	$	—		$	156		$	—

___________________


(a)	The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.


(b)	These swaps were settled on August 19, 2016.

Based on December 31, 2016 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $2.9 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. This total includes the $28 million loss currently deferred in AOCI. Estimated and realized gains or losses will change during future periods as market interest rates change.

Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2016 and 2015 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



	December 31, 2016
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,899	)	Interest expense	$	(953	)
Commodity derivatives	Revenue	11,019				—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(14		)		—
Total impact from cash flow hedges		$	7,106			$	(953	)



	December 31, 2015
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,647	)		$	—
Commodity derivatives	Revenue	14,460				—
Total		$	10,813			$	—



	December 31, 2014
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,669	)		$	—
Commodity derivatives	Revenue	(1,995		)		—
Total		$	(5,664	)		$	—

The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2016, 2015 and 2014. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.



	December 31, 2016			December 31, 2015			December 31, 2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	(31,222	)	$	2,888		$	(536	)
Forward commodity contracts	(573		)	9,782			14,681
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	3,899			3,647			3,669
Forward commodity contracts	(11,005		)	(14,460		)	1,995
Total other comprehensive income (loss) from hedging	$	(38,901	)	$	1,857		$	19,809

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2016, 2015 and 2014 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.



		2016			2015		2014
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income		Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Revenue	$	(50	)	$	—	$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	940			—		—
		$	890		$	—	$	—

As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our Utilities were $8.8 million and $24 million at December 31, 2016 and 2015, respectively.

- 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

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+ Details

Fair Value Measurements:

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances during 2016 or 2015. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

A discussion of fair value of financial instruments is included in Note 11. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):



	As of December 31, 2016
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	2,886	$	—	$	(2,733	)	$	153
Commodity derivatives - Utilities	—		7,469		—		(3,262		)	4,207
Interest rate swaps	—		—		—		—			—
Total	$	—	$	10,355	$	—	$	(5,995	)	$	4,360

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	1,586	$	—	$	—		$	1,586
Commodity derivatives - Utilities	—		12,201		—		(11,144		)	1,057
Interest rate swaps	—		90		—		—			90
Total	$	—	$	13,877	$	—	$	(11,144	)	$	2,733



	As of December 31, 2015
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,644	$	—	$	(10,644	)	$	—
Commodity derivatives - Utilities	—		2,293		—		(2,293		)	—
Interest rate swaps	—		3,441		—		—			3,441
Total	$	—	$	16,378	$	—	$	(12,937	)	$	3,441

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	556	$	—	$	(556	)	$	—
Commodity derivatives - Utilities	—		24,585		—		(24,585		)	—
Interest rate swaps	—		2,991		—		—			2,991
Total	$	—	$	28,132	$	—	$	(25,141	)	$	2,991

Fair Value Measures by Balance Sheet Classification

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

The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):



		2016				2015
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets - current	$	1,161	$	—	$	9,981	$	—
Commodity derivatives	Derivative assets - non-current	124		—		663		—
Interest rate swaps	Derivative assets - non-current	—		—		3,441		—
Commodity derivatives	Derivative liabilities - current	—		1,090		—		465
Commodity derivatives	Derivative liabilities - non-current	—		238		—		91
Interest rate swaps	Derivative liabilities - current	—		90		—		2,835
Interest rate swaps	Derivative liabilities - non-current	—		—		—		156
Total derivatives designated as hedges		$	1,285	$	1,418	$	14,085	$	3,547

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	2,977	$	—	$	—	$	—
Commodity derivatives	Derivative assets - non-current	98		—		—		—
Commodity derivatives	Derivative liabilities - current	—		1,279		—		9,586
Commodity derivatives	Derivative liabilities - non-current	—		36		—		12,706
Interest rate swaps	Derivative liabilities - current	—		—		—		—
Interest rate swaps	Derivative liabilities - non-current	—		—		—		—
Total derivatives not designated as hedges		$	3,075	$	1,315	$	—	$	22,292

Derivatives Offsetting

It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting for our accounts receivable and payable and derivative activities.

As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2016 and December 31, 2015, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure.

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2016 was as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	2,886	$	(2,733	)	$	153
Utilities	4,269		(3,262		)	1,007
Interest Rate Swaps	—		—			—
Total derivative assets subject to a master netting agreement or similar arrangement	7,155		(5,995		)	1,160

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	3,200		—			3,200
Interest rate swaps	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	3,200		—			3,200

Total derivative assets	$	10,355	$	(5,995	)	$	4,360



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	1,586	$	—		$	1,586
Utilities	11,144		(11,144		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	12,730		(11,144		)	1,586

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	1,057		—			1,057
Interest Rate Swaps	90		—			90
Total derivative liabilities not subject to a master netting agreement or similar arrangement	1,147		—			1,147

Total derivative liabilities	$	13,877	$	(11,144	)	$	2,733

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2015 were as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	10,644	$	(10,644	)	$	—
Utilities	2,293		(2,293		)	—
Interest rate swaps	3,441		—			3,441
Total derivative assets subject to a master netting agreement or similar arrangement	16,378		(12,937		)	3,441

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	—		—			—
Interest rate swaps	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	—		—			—

Total derivative assets	$	16,378	$	(12,937	)	$	3,441



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	556	$	(556	)	$	—
Utilities	24,585		(24,585		)	—
Interest Rate Swaps	2,991		—			2,991
Total derivative liabilities subject to a master netting agreement or similar arrangement	28,132		(25,141		)	2,991

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	—		—			—
Interest Rate Swaps	—		—			—
Total derivative liabilities not subject to a master netting agreement or similar arrangement	—		—			—

Total derivative liabilities	$	28,132	$	(25,141	)	$	2,991

Fair Value Of Financial Instruments:

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):



	2016				2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	13,580	$	13,580	$	440,861	$	440,861
Restricted cash and equivalents ^(a)	$	2,274	$	2,274	$	1,697	$	1,697
Notes payable ^(b)	$	96,600	$	96,600	$	76,800	$	76,800
Long-term debt, including current maturities ^(c)	$	3,216,932	$	3,351,305	$	1,853,682	$	1,992,274

_______________


(a)	Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy.


(b)	Notes payable consist of borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


(c)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds, and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank. Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal.

Restricted Cash and Equivalents

Restricted cash and cash equivalents represent restricted cash and uninsured term deposits.

Notes Payable and Long-Term Debt

For additional information on our notes payable and long-term debt, see Note 6 and Note 7.

- 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

Equity:

12 Months Ended

Dec. 31, 2016

Stockholders' Equity Note [Abstract]

Stock

EQUITY

Equity Units

On November 23, 2015, we issued 5.98 million equity units for total gross proceeds of $299 million. Each Equity Unit has a stated amount of $50 and consists of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. The RSNs, a debt instrument, and the forward purchase contracts, an equity instrument, are deemed to be separate instruments as the investor may trade the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately.

The forward purchase contracts obligate the holders to purchase from the Company on the settlement date, which shall be no later than November 1, 2018, for a price of $50 in cash, the following number of shares of our common stock, subject to anti-dilution adjustments:

•

if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938, 1.0572 shares of the Company’s common stock per Equity Unit;


•	if the AMV is less than $47.2938 but greater than $40.25, a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50; and


•	if the AMV is less than or equal to $40.25, 1.2422 shares of the Company’s common stock.

The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing, the interest rate on the RSNs will not be reset, and the holders of the RSNs will have the right to put the RSNs to the Company at a price equal to 100% of the principal amount, and the proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts.

The Company will also pay the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million, is recorded as a reduction of shareholders’ equity. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2016, the forward purchase contracts were dilutive and therefore included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders.

Selected information about our equity units is presented below (in thousands except for percentages):



Issuance Date	Units Issued	Total Net Proceeds		Total Long-term Debt (RSNs)		RSN Interest Rate (annual)		Stock Purchase Contract Rate (annual)		Stock Purchase Contract Liability as of December 31, 2016
11/23/2015	5,980	$	290,030	$	299,000	3.50	%	4.25	%	$	23,335

At-the-Market Equity Offering Program

On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the three months ended December 31, 2016, we issued 218,647 common shares for $13 million, net of $0.1 million in commissions under the ATM equity offering program. Through December 31, 2016, we have sold and issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions. As of December 31, 2016, there were no shares sold that were not settled.

Common Stock Offering

On November 23, 2015, we issued 6.325 million shares of Common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million. The proceeds from the offering were used to partially fund the purchase of SourceGas, which closed on February 12, 2016.

Equity Compensation Plans

Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 1,115,557 shares available to grant at December 31, 2016.

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2016, total unrecognized compensation expense related to non-vested stock awards was approximately $13.5 million and is expected to be recognized over a weighted-average period of 2.0 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):



	2016		2015		2014
Stock-based compensation expense	$	10,885	$	4,076	$	9,329

Stock Options

The Company has not issued any stock options since 2014 and has 119,415 stock options outstanding at December 31, 2016. The amount of stock options granted during the last three years, related exercise activity and the number of stock options outstanding at December 31, 2016 are not material to the Company’s consolidated financial statements.

Restricted Stock

The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.

A summary of the status of the restricted stock and restricted stock units at December 31, 2016, was as follows:



	Restricted Stock		Weighted-Average Grant Date Fair Value
	(in thousands)
Balance at beginning of period	202		$	48.96
Granted	195		53.55
Vested	(88	)	48.00
Forfeited	(14	)	51.89
Balance at end of period	295		$	52.15

The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2016	$	53.55	$	4,602
2015	$	50.01	$	6,009
2014	$	54.34	$	6,114

As of December 31, 2016, there was $10.3 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.3 million at December 31, 2016 would be reclassified as a liability.

Outstanding performance periods at December 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
January 1, 2014	January 1, 2014 - December 31, 2016	44	0%	200%
January 1, 2015	January 1, 2015 - December 31, 2017	43	0%	200%
January 1, 2016	January 1, 2016 - December 31, 2018	53	0%	200%

A summary of the status of the Performance Share Plan at December 31 was as follows:



	Equity Portion				Liability Portion
			Weighted-Average Grant Date Fair Value^(a)				Weighted-Average Fair Value at
	Shares		Weighted-Average Grant Date Fair Value^(a)		Shares		December 31, 2016
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	74		$	47.21	74
Granted	27		47.76		27
Forfeited	—		—		—
Vested	(30	)	35.86		(30	)
Performance Shares balance at end of period	71		$	52.29	71		$	48.05

_____________________


(a)	The grant date fair values for the performance shares granted in 2016, 2015 and 2014 were determined by Monte Carlo simulation using a blended volatility of 24%, 21% and 23%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:



	Weighted Average Grant Date Fair Value
December 31, 2016	$	47.76
December 31, 2015	$	54.92
December 31, 2014	$	55.18

Performance plan payouts have been as follows (dollars and shares in thousands):



Performance Period	Year of Payment	Shares Issued	Cash Paid		Total Intrinsic Value
January 1, 2013 to December 31, 2015	2016	—	$	—	$	—
January 1, 2012 to December 31, 2014	2015	69	$	3,657	$	7,314
January 1, 2011 to December 31, 2013	2014	59	$	3,011	$	6,020

On January 24, 2017, the Compensation Committee of our Board of Directors determined that the Company’s performance criteria for the January 1, 2014 through December 31, 2016 performance period was not met. As a result, there will be no payout for this period.

As of December 31, 2016, there was $3.1 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.8 years.

Shareholder Dividend Reinvestment and Stock Purchase Plan

We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We are currently issuing new shares.

A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands):



	2016		2015
Shares Issued	51		66

Weighted Average Price	$	58.24	$	44.79

Unissued Shares Available	356		408

Preferred Stock

Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding.

Sale of Noncontrolling Interest in Subsidiary

Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes.

ASC 810 requires the accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation.

Net income available for common stock for the year ended December 31, 2016, was reduced by $9.6 million attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments.

Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations.

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:



	2016		2015
	(in thousands)
Assets
Current assets	$	12,627	$	—
Property, plant and equipment of variable interest entities, net	$	218,798	$	—

Liabilities
Current liabilities	$	4,342	$	—

- 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

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+ Details

Impairment Of Assets:	12 Months Ended
Impairment Of Assets:	Dec. 31, 2016
Asset Impairment Charges [Abstract]
Impairment of Assets	IMPAIRMENT OF ASSETS Long-lived assets Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. As a result of continued low commodity prices throughout 2016, we have recorded non-cash ceiling test impairments of oil and gas assets included in the Oil and Gas segment totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead. In 2015, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment totaling approximately $250 million for the year ended December 31, 2015. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead. During the second quarter of 2016, we advanced our Oil and Gas strategy, identifying certain non-core assets which may be sold as they are not expected to be utilized in the Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the impairments noted above. The remaining book value of these depreciable assets is approximately $23 million as of December 31, 2016. Equity investments in unconsolidated subsidiaries Our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, due to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements. We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million, the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system.

Operating Leases:

12 Months Ended

Dec. 31, 2016

Leases, Operating [Abstract]

Operating Leases

OPERATING LEASES

We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):



	2016		2015		2014
Rent expense	$	9,568	$	7,177	$	6,932

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):



2017	$	6,739
2018	$	5,564
2019	$	4,441
2020	$	2,639
2021	$	1,652
Thereafter	$	6,245

Income Taxes:

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):



	2016			2015			2014
Current:
Federal	$	(23,820	)	$	2,549		$	(2,319	)
State	(1,922		)	1,319			(1,288		)
	(25,742		)	3,868			(3,607		)
Deferred:
Federal	36,012			(23,592		)	64,780
State	257			(2,323		)	5,658
Tax credit amortization	(52		)	(113		)	(206		)
	36,217			(26,028		)	70,232

	$	10,475		$	(22,160	)	$	66,625

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):



	2016			2015
Deferred tax assets:
Regulatory liabilities	$	58,200		$	43,586
Employee benefits	29,638			26,400
Federal net operating loss	252,780			217,922
Other deferred tax assets^(a)	83,485			85,907
Less: Valuation allowance	(9,263		)	(4,304		)
Total deferred tax assets	414,840			369,511

Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences^(b)	(820,111		)	(711,293		)
Regulatory assets	(49,471		)	(29,092		)
State deferred tax liability	(47,987		)	(35,065		)
Deferred costs	(18,551		)	(26,121		)
Other deferred tax liabilities	(14,326		)	(18,519		)
Total deferred tax liabilities	(950,446		)	(820,090		)

Net deferred tax liability	$	(535,606	)	$	(450,579	)

_______________


(a)	Other deferred tax assets consist primarily of state tax credits, state net operating loss, alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.


(b)	To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million, previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration.

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:



	2016		2015		2014
Federal statutory rate ^(e)	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	0.2		1.0		1.1
Amortization of excess deferred income taxes and investment tax credits	(0.1	)	0.2		(0.1	)
Percentage depletion^(a)	(8.2	)	3.5		(1.0	)
Non-controlling interest^(d)	(3.6	)	—		—
Equity AFUDC	(1.1	)	0.3		(0.1	)
Tax credits	(1.5	)	0.5		(0.1	)
Transaction costs	1.1		—		—
Accounting for uncertain tax positions adjustment^(b)	(6.0	)	(3.5	)	(0.1	)
Flow-through adjustments^(c)	(5.1	)	3.8		(0.9	)
Other tax differences	0.6		—		(0.1	)
	11.3	%	40.8	%	33.7	%

_________________________


(a)	The tax benefit includes additional percentage depletion deductions that were claimed with respect to the oil and gas properties involving prior tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.

(b)

The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

(c)

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


(d)	Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded.


(e)	The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net loss.

At December 31, 2016, we have federal and gross state NOL carryforwards that will expire at various dates as follows (in thousands):



	Amounts		Expiration Dates
Federal Net Operating Loss Carryforward	$	721,075	2019	to	2036

State Net Operating Loss Carryforward	$	616,524	2017	to	2036

As of December 31, 2016, we had a $0.9 million valuation allowance against the state NOL carryforwards. Our 2016 analysis of the ability to utilize such NOLs resulted in a slight increase of the valuation allowance of approximately $0.1 million, which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2016. Such a decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.

The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):



	Changes in Uncertain Tax Positions
Beginning balance at January 1, 2014	$	37,631
Additions for prior year tax positions	1,253
Reductions for prior year tax positions	(6,692		)
Additions for current year tax positions	—
Settlements	—
Ending balance at December 31, 2014	32,192
Additions for prior year tax positions	3,285
Reductions for prior year tax positions	(3,491		)
Additions for current year tax positions	—
Settlements	—
Ending balance at December 31, 2015	31,986
Additions for prior year tax positions	2,423
Reductions for prior year tax positions	(19,174		)
Additions for current year tax positions	—
Settlements	(11,643		)
Ending balance at December 31, 2016	$	3,592

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.7 million.

As a result of an agreement in principle that was reached with IRS Appeals in the first quarter of 2016, we recognized no interest expense for the year ended December 31, 2016, and approximately $1.8 million and $1.6 million for the years ended December 31, 2015 and 2014, respectively.

We had no accrued interest (before tax effect) associated with income taxes at December 31, 2016, and approximately $13.3 million accrued at December 31, 2015.

We file income tax returns with the IRS and various state jurisdictions. We received a 30-day Letter along with a Revenue Agent’s Report from the IRS in regards to the audit of the 2007 to 2009 tax years. A protest was timely filed with the IRS in August 2014 related to the like-kind exchange transaction described below and research and development (“R&D”) credits and deductions claimed with respect to certain costs and projects. A settlement in principle was reached with IRS Appeals in the first quarter of 2016. We are also currently under examination by the IRS for the 2010 to 2012 tax years. We received a 30-day letter along with Revenue Agent’s Report from the IRS in regard to the audit of the 2010 to 2012 tax years. A protest was timely filed with IRS Appeals in the second quarter of 2016 related to R&D credits and deductions claimed with respect to certain costs and projects.

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. The settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable.

As of December 31, 2016, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2017.

Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2016, we had foreign tax credit carryforwards of approximately $2.3 million, which expire in 2017.

We had a $1.7 million and $0.5 million valuation allowance against the foreign tax credit carryforwards as of December 31, 2016 and 2015 respectively. Approximately $1.8 million of foreign tax credits was previously reflected as an offset to liabilities for unrecognized tax benefits in recognition of the estimated impact the resolution of material uncertain tax positions could have with respect to utilization. Subsequent to the settlement agreement in principle that was reached with IRS Appeals in the first quarter of 2016, it has been determined to be more beneficial to deduct the $1.8 million of foreign tax credits. In determining the valuation allowance amount, we compared the tax benefit associated with either deducting foreign taxes or claiming them as credits. The tax benefit of being able to deduct such foreign tax credits is approximately $0.6 million resulting in an increase to the valuation allowance of approximately $1.2 million.

State tax credits have been generated and are available to offset future state income taxes. At December 31, 2016, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
Investment tax credit	$	19,765	2023	to	2036
Research and development	$	167	No expiration

As of December 31, 2016, we had a $6.6 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.6 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.7 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2016. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

Other Comprehensive Income:

12 Months Ended

Dec. 31, 2016

Statement of Comprehensive Income [Abstract]

Other Comprehensive Income

OTHER COMPREHENSIVE INCOME

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):



	Location on the Consolidated Statements of Income (Loss)	Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income (Loss)	December 31, 2016			December 31, 2015
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(3,899	)	$	(3,647	)
Commodity contracts	Revenue	11,019			14,460
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(14		)	—
		7,106			10,813
Income tax	Income tax benefit (expense)	(2,702		)	(4,271		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	4,404		$	6,542

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	221		$	238
Actuarial gain (loss)	Operations and maintenance	(1,978		)	(2,822		)
		(1,757		)	(2,584		)
Income tax	Income tax benefit (expense)	533			884
Total reclassification adjustments related to defined benefit plans, net of tax		$	(1,224	)	$	(1,700	)
Total reclassifications		$	3,180		$	4,842

Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2015	$	(341	)	$	7,066		$	(15,780	)	$	(9,055	)
Other comprehensive income (loss)
before reclassifications	(20,302		)	(361		)	(1,985		)	(22,648		)
Amounts reclassified from AOCI	2,534			(6,938		)	1,224			(3,180		)
As of December 31, 2016	$	(18,109	)	$	(233	)	$	(16,541	)	$	(34,883	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2014	$	(4,930	)	$	10,023		$	(20,137	)	$	(15,044	)
Other comprehensive income (loss)
before reclassifications	2,290			5,884			2,657			10,831
Amounts reclassified from AOCI	2,299			(8,841		)	1,700			(4,842		)
As of December 31, 2015	$	(341	)	$	7,066		$	(15,780	)	$	(9,055	)

- 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

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-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6522872

+ Details

Supplemental Disclosure of Cash flow Information:

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Years ended December 31,	2016			2015			2014
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	29,082		$	40,250		$	52,584
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	8,577		$	(518	)	$	(5,634	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(112,925	)	$	(77,810	)	$	(69,239	)
Income taxes, net	$	(1,156	)	$	(1,202	)	$	(413	)

Employee Benefit Plans:

12 Months Ended

Dec. 31, 2016

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

On February 12, 2016, as disclosed in Note 2, we completed the acquisition of SourceGas, adding an additional defined benefit pension plan, two additional defined benefit healthcare postretirement plans and a 401K retirement savings plan to cover employees of the utilities acquired. Benefits under these plans are determined based on each employee’s compensation, years of service, and/or age at retirement, among other factors.

In accordance with accounting standards, the SourceGas benefit liabilities were re-measured as of February 11, 2016. In addition, prior service costs not previously expensed were reclassified to a Regulatory asset and will be amortized over the average remaining service life of the plans.

Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands):

Defined Contribution Plans

We sponsor 401(k) retirement savings plans (the 401(k) Plans). Participants in the 401(k) Plans may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plans provide employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plans provide a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Retirement Contribution based on the participant’s age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company.

Defined Benefit Pension Plans (Pension Plans)

During 2016 we maintained three defined benefit pension plans, BHC Pension Plan, Black Hills Utility Holding, Inc. Pension Plan and SourceGas Retirement Plan that as of December 31, 2016 were merged into one single plan, the Black Hills Retirement Plan. The Pension Plans cover certain eligible employees of the Company. The benefits for the Pension Plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. All three Pension Plans have been closed to new employees and certain employees who did not meet age and service based criteria.

Black Hills Retirement Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016, reporting beginning in 2017 will no longer represent an undivided interest in the Master Trust. Our Board of Directors has approved the Plans’ investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plans’ beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ assets consist primarily of equity, fixed income and hedged investments.

The expected rate of return on pension plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2016, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 40% to 50% equity securities and 50% to 60% fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets is based on the targeted asset allocation range of 30% to 40% equity securities and 60% to 70% fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.

The expected long-term rate of return for investments was 6.75% for the BHC Pension Plan and Black Hills Utility Holding, Inc. Plan 2016 and 2015 plan years and 7.5% for the SourceGas Retirement Plan 2016 plan year. Our Pension Plan is funded in compliance with the federal government’s funding requirements.

Plan Assets

The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows:



	2016	2015
Equity	28%	26%
Real estate	5	5
Fixed income	57	59
Cash	2	1
Hedge funds	8	9
Total	100%	100%

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company.

Plan Assets

We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid.

Non-pension Defined Benefit Postretirement Healthcare Plans

With the addition of the two SourceGas Postretirement Healthcare Plans, BHC now sponsors five retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via VEBAs and a Grantor Trust. Effective January 1, 2014, health care coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange for BHC and Black Hills Utility Holdings retirees. SourceGas retirees do not participate in the individual market healthcare exchange; therefore, all permissible health claims are paid under the self-insured plan.

Plan Assets

We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provides for partial pre-funding via VEBAs and a Grantor Trust. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Kansas and Iowa. We do not pre-fund the Healthcare Plans for those employees outside Arkansas, Kansas and Iowa.

Plan Contributions

Contributions to the Pension Plans are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions for the years ended December 31 were as follows (in thousands):



	2016		2015
Defined Contribution Plan
Company Retirement Contribution	$	9,632	$	5,564
Matching contributions	$	9,645	$	9,616



	2016		2015
Defined Benefit Plans
Defined Benefit Pension Plans	$	14,200	$	10,200
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,965	$	3,771
Supplemental Non-Qualified Defined Benefit Plans	$	1,565	$	1,564

While we do not have required contributions, we expect to make approximately $10 million in contributions to our Defined Benefit Pension Plans in 2017.

Fair Value Measurements

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Defined Benefit Pension Plans	December 31, 2016
	Level 1		Level 2		Level 3		NAV ^(a)		Total
AXA Equitable General Fixed Income	$	—	$	1,325	$	—	—		$	1,325
Common Collective Trust - Cash and Cash Equivalents	—		5,307		—		—		5,307
Common Collective Trust - Equity	—		101,020		—		—		101,020
Common Collective Trust - Fixed Income	—		209,815		—		—		209,815
Common Collective Trust - Real Estate	—		2,349		—		15,563		17,912
Hedge Funds	—		—		—		29,316		29,316
Total investments measured at fair value	$	—	$	319,816	$	—	$	44,879	$	364,695



Defined Benefit Pension Plans	December 31, 2015
	Level 1		Level 2		Level 3		NAV ^(a)		Total
AXA Equitable General Fixed Income	$	—	$	1,072	$	—	$	—	$	1,072
Common Collective Trust - Cash and Cash Equivalents	—		1,556		—		—		1,556
Common Collective Trust - Equity	—		74,885		—		—		74,885
Common Collective Trust - Fixed Income	—		172,016		—		—		172,016
Common Collective Trust - Real Estate	—		2,204		—		11,143		13,347
Hedge Funds	—		—		—		25,746		25,746
Total investments measured at fair value	$	—	$	251,733	$	—	$	36,889	$	288,622

_____________

(a)

Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.



Non-pension Defined Benefit Postretirement Healthcare Plans	December 31, 2016
	Level 1		Level 2		Level 3		Total
Cash and Cash Equivalents	$	111	$	—	$	—	$	111
Equity Securities	1,154		—		—		1,154
Registered Investment Company Trust - Money Market Mutual Fund	—		4,732		—		4,732
Intermediate-term Bond	—		2,473		—		2,473
Total investments measured at fair value	$	1,265	$	7,205	$	—	$	8,470



Non-pension Defined Benefit Postretirement Healthcare Plans	December 31, 2015
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,681	$	—	$	4,681
Total investments measured at fair value	$	—	$	4,681	$	—	$	4,681

Additional information about assets of the Benefit Plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:

Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (EFTs) for diversification into the other sectors of the economy. EFTs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1.

Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2.

AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately place bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates at which loans with similar characteristics have. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2.

Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2.

The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.

Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments, and rely on these reports for pricing the units of the fund. Certain of the funds’ assets contain participant withdrawal policy.

Hedge Funds: Hedge funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.

Other Plan Information

The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of AOCI (in thousands):

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2016			2015			2016			2015			2016			2015
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	356,575		$	377,772		$	40,219		$	41,211		$	48,077		$	49,042
Transfer from SourceGas Acquisition	75,254			—			—			—			15,091			—
Service cost	7,619			6,093			2,099			1,300			1,757			1,808
Interest cost	15,743			15,522			1,257			1,455			1,942			1,801
Actuarial (gain) loss ^(a)	7,001			(28,229		)	2,049			(2,072		)	2,808			(1,206		)
Amendments	—			—			—			—			2,203			—
Benefits paid	(22,013		)	(14,583		)	(1,755		)	(1,675		)	(4,965		)	(3,771		)
Medicare Part D accrued	—			—			—			—			—			(178		)
Plan participants’ contributions	—			—			—			—			1,110			581
Projected benefit obligation at end of year	$	440,179		$	356,575		$	43,869		$	40,219		$	68,023		$	48,077

____________________


(a)	Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates.



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2016			2015			2016		2015		2016			2015

Beginning fair value of plan assets	$	288,622		$	299,533		$	—	$	—	$	4,681		$	4,705
Transfer from SourceGas Acquisition	53,067			—			—		—		3,340			—
Investment income (loss)	30,819			(6,528		)	—		—		256			(9		)
Employer contributions	14,200			10,200			—		—		4,048			3,175
Retiree contributions	—			—			—		—		1,110			581
Benefits paid	(22,013		)	(14,583		)	—		—		(4,965		)	(3,771		)
Plan administrative expenses	—			—			—		—		—			—
Ending fair value of plan assets	$	364,695		$	288,622		$	—	$	—	$	8,470		$	4,681

____________________


(a)	Assets of VEBAs and Grantor Trust.

The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016		2015
Regulatory assets	$	66,640	$	68,915	$	—	$	—	$	11,401	$	6,464
Current liabilities	$	—	$	—	$	1,583	$	1,568	$	4,360	$	3,543
Non-current assets	$	—	$	—	$	—	$	—	$	21	$	23
Non-current liabilities	$	75,484	$	67,953	$	42,286	$	38,651	$	55,214	$	39,855
Regulatory liabilities	$	5,195	$	—	$	—	$	—	$	3,419	$	3,209

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016		2015
Accumulated Benefit Obligation^(a)	$	416,786	$	334,923	$	32,090	$	30,558	$	68,023	$	48,077

____________________

(a)

The Defined Benefit Pension Plans Accumulated Benefit Obligation for 2016 represents the obligation for the merged Black Hills Retirement Plan. The 2015 obligation represents the BHC Pension Plan and Black Hills Utility Holding, Inc. Pension Plan and has been combined for presentation purposes to conform to the 2016 merged plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2016 represents that obligation for the five postretirement plans maintained by BHC. The 2015 obligation represents the three postretirement plans maintained by BHC.

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2016			2015			2014			2016		2015		2014		2016			2015			2014
Service cost	$	7,619		$	6,093		$	5,448		$	1,335	$	1,380	$	1,498	$	1,757		$	1,808		$	1,700
Interest cost	15,743			15,522			15,852			1,257		1,455		1,447		1,942			1,801			1,919
Expected return on assets	(23,062		)	(19,470		)	(18,065		)	—		—		—		(279		)	(131		)	(85		)
Net amortization of prior service cost	58			58			62			2		2		2		(428		)	(428		)	(428		)
Recognized net actuarial loss (gain)	7,173			11,037			4,806			829		1,081		498		335			408			160
Settlement Expense^(a)	10			—			—			—		—		—		—			—			—
Net periodic expense	$	7,541		$	13,240		$	8,103		$	3,423	$	3,918	$	3,445	$	3,327		$	3,458		$	3,266

____________________


(a)	Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.

AOCI

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016			2015
Net (gain) loss	$	8,472	$	8,777	$	7,132	$	6,339	$	1,595		$	1,704
Prior service cost (gain)	31		41		5		6		(694		)	(1,087		)
Total AOCI	$	8,503	$	8,818	$	7,137	$	6,345	$	901		$	617

The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2017 are as follows (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	2,604	$	572	$	325
Prior service cost (credit)	38		1		(368		)
Total net periodic benefit cost expected to be recognized during calendar year 2017	$	2,642	$	573	$	(43	)

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:	2016		2015		2014		2016		2015		2014		2016		2015		2014

Discount rate	4.27	%	4.58	%	4.19	%	4.02	%	4.28	%	4.19	%	3.96	%	4.17	%	3.82	%
Rate of increase in compensation levels	3.47	%	3.51	%	3.76	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2016		2015		2014		2016		2015		2014		2016		2015		2014

Discount rate ^(a)	4.50	%	4.19	%	5.04	%	4.28	%	4.19	%	5.03	%	4.18	%	3.82	%	4.46	%
Expected long-term rate of return on assets ^(b)	6.87	%	6.75	%	6.75	%	N/A		N/A		N/A		3.83	%	3.00	%	2.00	%
Rate of increase in compensation levels	3.42	%	3.76	%	3.76	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the merged Black Hills Retirement Plan is 4.27% for the calculation of the 2017 net periodic pension costs.


(b)	The expected rate of return on plan assets is 6.75% for the calculation of the 2017 net periodic pension cost.

The healthcare benefit obligation was determined at December 31 as follows:



	2016 ^(a)	2015
Trend Rate - Medical
Pre-65 for next year - All Plans	6.10%	6.35%
Pre-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2024	2024

Post-65 for next year - All Plans	5.10%	5.20%
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2023	2023

_____________________________


(a)	The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.

We do not pre-fund our supplemental plans or three of the five healthcare plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on December 31, 2016 Accumulated Postretirement Benefit Obligation			Impact on 2017 Service and Interest Cost
Increase 1%	$	2,569		$	156
Decrease 1%	$	(2,191	)	$	(131	)

Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company accounted for this change as a change in estimate prospectively beginning in the first quarter of 2016. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details.

The following benefit payments, which reflect future service, are expected to be paid (in thousands):



	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-Pension Defined Benefit Postretirement Healthcare Plans
2017	$	21,355	$	1,583	$	5,504
2018	$	21,566	$	1,809	$	5,779
2019	$	23,010	$	1,921	$	5,886
2020	$	27,028	$	1,634	$	5,983
2021	$	27,614	$	1,836	$	5,931
2022-2026	$	149,893	$	11,009	$	27,585

Commitments And Contingencies:

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:

•

Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.


•	South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.


•	South Dakota Electric has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.


•	Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate inter-company agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.


•	Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate inter-company agreement, Wyoming Electric has agreed to sell 20 MW of energy from Silver Sage to South Dakota Electric.


•	Colorado Electric’s REPA with AltaGas expiring October 16, 2037, provides up to 14.5 MW of wind energy from the Busch Ranch Wind Farm in which Colorado Electric owns a 50% undivided ownership interest.

Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):



	2016		2015		2014
PPA with PacifiCorp	$	12,221	$	13,990	$	13,943
Transmission services agreement with PacifiCorp	$	1,428	$	1,213	$	1,227
PPA with Happy Jack	$	3,836	$	3,155	$	3,919
PPA with Silver Sage	$	4,949	$	4,107	$	4,798
Busch Ranch Wind Farm	$	2,071	$	1,734	$	1,998
PPAs with Cargill ^(a)	$	10,995	$	16,112	$	9,286

________________


(a)	PPAs with Cargill expired on December 31, 2016.

Other Gas Supply Agreements

Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044.

Natural Gas Delivery Commitment

In 2012, we entered into a ten-year gas gathering and processing contract for natural gas production from our properties in the Piceance Basin in Colorado, under which we pay a gathering fee per Mcf. This take or pay contract requires us to pay the fee on a minimum of 20,000 Mcf per day, regardless of the volume delivered. The 10 year agreement expiring in 2024 became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes.

Purchase Commitments

We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract.

Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2016, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):



	CIG Rockies	Enable-East	NWPL-Wyoming	SSTAR-TEXOK	Other
2017	5,549,427	620,300	1,208,000	457,399	44,913
2018	—	584,000	1,208,000	—	—
2019	—	584,000	720,000	—	—
2020	—	585,600	—	—	—
2021	—	388,800	—	—	—

Purchases under these contracts totaled $31 million, $48 million and $31 million for 2016, 2015 and 2014, respectively.

The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, gathering commitments, coal and natural gas transportation and storage agreements (in thousands):



	Power Purchase Agreements		Transportation, storage, gathering and coal agreements
2017	$	26,690	$	136,607
2018	$	8,934	$	120,123
2019	$	6,388	$	87,210
2020	$	6,388	$	82,247
2021	$	5,755	$	75,424
Thereafter	$	11,509	$	225,765

Future Purchase Agreement - Related Party

Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022, includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.6 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment.

Power Sales Agreements

Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:


•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU.


•	South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership.

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.


•	South Dakota Electric has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations.

Reimbursement Agreement

We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.

Environmental Matters

We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. They can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies.

Air

Our generation facilities are subject to federal, state and local laws and regulations relating to the protection of air quality. These laws and regulations cover, among other pollutants, carbon monoxide, SO₂, NO_x, mercury, hazardous air pollutants, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen I, Wygen II, Wygen III, Wyodak and Pueblo Airport Generating Station plants. Title IV of the Clean Air Act created an SO₂ allowance trading program as part of the federal acid rain program. Without purchasing additional allowances, we currently hold sufficient allowances to satisfy Title IV at all such plants through 2046.

The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which imposed emission limits, fuel requirements and monitoring requirements. The rule had a compliance deadline of March 21, 2014. In anticipation of this rule we suspended operations at the Osage plant in October 2010 and as a result of this rule, we suspended operations at the Ben French facility on August 31, 2012. We permanently retired Ben French, Osage and Neil Simpson I on March 21, 2014. In conjunction with the Colorado Clean Air Clean Jobs Act, the CPUC issued an order approving the closure of the W.N. Clark facility no later than December 31, 2013. This facility suspended operations December 31, 2012 and was retired on December 31, 2013. The net book value of these plants was allowed regulatory accounting treatment and is recorded as a Regulatory Asset on the Consolidated Balance Sheet. The CPUC also approved a CPCN for the retirement of Pueblo Units #5 and #6 effective December 31, 2013.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date.

In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date.

Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages.

Reclamation Liability

For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.

See Note 8 for additional information.

Manufactured Gas Processing

As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.5 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.

In March 2011, Nebraska Gas executed an Allocation, Indemnification and Access Agreement with the successor to the former operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed to remediate the Blair and Plattsmouth sites in Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth in Nebraska's Voluntary Cleanup Program. Site remediation was completed in September 2012. However, there was a potential for additional minimal remediation work at Plattsmouth where monitoring was required until 2015. Both Nebraska sites were required to monitor groundwater quality for a minimum two year period, ending in 2015. In late 2015, groundwater concentrations were proposed and approved by the Nebraska Department of Environmental Quality as meeting steady or declining pollution levels. We assembled our final removal action completion reports to formally close the site, and submitted reports to the Nebraska Department of Environmental Quality in December 2015. In 2016, we received state approval for “no further action” at both sites.

As of December 31, 2016, our estimated liabilities for Iowa’s MGP sites currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of sites as of December 31, 2016 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets.

Prior to Black Hills Corporation's ownership, Aquila received rate orders that enabled recovery of environmental cleanup costs in certain jurisdictions. We anticipate recovery of these current and future costs would be allowed. Additionally, we may pursue recovery or agreements with other potentially responsible parties when and where permitted.

As a result of the SourceGas Transaction, we acquired potential liability for at least one former MGP site in McCook, Nebraska. The Nebraska Department of Environmental Quality conducted a limited assessment in 2012 which documented soil and groundwater impacts. However, there has been no directive from the state to pursue either remediation or further assessment. We are currently evaluating the potential for other Potential Responsible Parties and future comprehensive analysis to fully determine and delineate the extent of contamination. The assigned liability for this site cannot be determined at this time. However, based on the state’s assessment, we anticipate costs will be less than $1.0 million.

Legal Proceedings

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.

In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

Guarantees:

12 Months Ended

Dec. 31, 2016

Guarantees [Abstract]

Guarantees

GUARANTEES

We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee.

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	December 31, 2016		Expiration
Indemnification for subsidiary reclamation/surety bonds ^(a)	$	57,105	Ongoing
	$	57,105

_______________________


(a)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited):

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Reserves (Unaudited)

OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 713 gross developed oil and gas wells in 9 states and holds leases on approximately 127,919 net acres.

Costs Incurred

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):



	2016		2015		2014
Acquisition of properties:
Proved	$	—	$	1,407	$	4,881
Unproved	910		669		5,056
Exploration costs	1,102		35,434		54,355
Development costs	4,657		128,998		52,262
Asset retirement obligations incurred	—		566		68
Total costs incurred	$	6,669	$	167,074	$	116,622

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016, 2015 and 2014 and a reconciliation of the changes between these dates. These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.



	2016										2015										2014
	Oil			Gas			NGL				Oil			Gas			NGL				Oil			Gas			NGL
	(in Mbbls of oil and NGL, and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	3,450			73,412			1,752				4,276			65,440			1,720				3,921			63,190			—
Production ^(a)	(319		)	(9,430		)	(133		)		(371		)	(10,058		)	(102		)		(337		)	(7,156		)	(135		)
Sales	(570		)	(1,291		)	(17		)		(11		)	(828		)	—				(40		)	(61		)	—
Additions - extensions and discoveries	3			52			—				199			24,462			232				733			11,003			182
Revisions to previous estimates	(322		)	(8,173		)	110				(643		)	(5,604		)	(98		)		(1		)	(1,536		)	1,673
Balance at end of year	2,242			54,570			1,712				3,450			73,412			1,752				4,276			65,440			1,720

Proved developed reserves at end of year included above	2,242			54,570			1,712				3,436			73,390			1,752				3,780			57,427			1,530

Proved undeveloped reserves at the end of year included in above	—			—			—				14			22			—				496			8,013			191

NYMEX prices	$	42.75		$	2.48		$	—		^(b)	$	50.28		$	2.59		$	—		^(b)	$	94.99		$	4.35		$	—		^(b)

Well-head reserve prices^(c)	$	37.35		$	2.25		$	11.92			$	44.72		$	1.27		$	18.96			$	85.80		$	3.33		$	34.81

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.


(b)	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.

(c)

For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

Reserve additions for 2016 totaled 0.1 Bcfe, replacing 0% of annual production. Reserve additions in 2016 were minimal due to continued poor economic conditions and our focus on supporting utility Cost of Service Gas Programs, which together, limited any further drilling. Capital spending in 2016 was primarily for existing infrastructure and acquiring right-aways. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program.

In 2016, we had negative revisions of (9.4 Bcfe) to previous reserve estimates. Most of the negative revision was the result of lower equivalent prices of oil, liquids and gas received at the wellhead of (12.3 Bcfe), partially offset by improved wellhead performance of 3.5 Bcfe.

SEC regulations require that PUD locations meet the test of being developed within five years of being categorized as proved. In 2016, we had no PUD locations that were required to be dropped because of the five year rule.

Companies are required to include a narrative disclosure of the total quantity of PUD locations at year end, any material changes in PUD locations during the year and investment and progress made in converting the PUD locations to proved developed during the year.


•	We have no PUDs at December 31, 2016, and due to economic conditions in 2016, no new gross PUD locations were added for future drilling in the Piceance Mancos or Powder River Basin.


•	The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2016 were:



	Proved Reserves (in Bcfe)		Gross PUD Locations		Future Development Costs (in millions)

Existing 2015:
Williston	0.1		6		$	0.5
Piceance	—		—		$	(0.1	)
Powder River	—		—		$	—
Year End Total 2015	0.1		6		$	0.4

Dropped 2016:
Williston	(0.1	)	(6	)	$	(0.5	)
Piceance	—		—		$	0.1
	(0.1	)	(6	)	$	(0.4	)

Drilled in 2016:
	—		—		$	—

Revisions:	—		—		$	—

Added in 2016:	—		—		$	—

Total Proved Undeveloped	—		—		$	—

Capitalized Costs

Following is information concerning capitalized costs for the years ended December 31 (in thousands):



	2016			2015			2014
Unproved oil and gas properties	$	18,547		$	47,254		$	75,329
Proved oil and gas properties	1,043,558			1,008,466			807,518
Gross capitalized costs	1,062,105			1,055,720			882,847

Accumulated depreciation, depletion and amortization and valuation allowances	(1,000,091		)	(888,775		)	(612,012		)
Net capitalized costs	$	62,014		$	166,945		$	270,835

Results of Operations

Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):



	2016			2015			2014
Revenue	$	34,058		$	43,283		$	55,114

Production costs	17,231			19,762			22,155
Depreciation, depletion and amortization	12,574			28,062			23,288
Impairment of long-lived assets	106,957			249,608			—
Total costs	136,762			297,432			45,443
Results of operations from producing activities before tax	(102,704		)	(254,149		)	9,671

Income tax benefit (expense)	37,916			93,743			(3,415		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	(64,788	)	$	(160,406	)	$	6,256

Unproved Properties

Unproved properties not subject to amortization at December 31, 2016, relate primarily to direct purchase leasehold and work-in-progress projects. Unproved properties not subject to amortization at December 31, 2015 and 2014 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million, $1.0 million and $1.0 million of interest during 2016, 2015 and 2014, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties. However, the timing of the ultimate evaluation and disposition of the properties has not been determined.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):



	2016		2015		2014		Prior		Total
Leasehold acquisition cost	$	963	$	—	$	—	$	9,278	$	10,241
Exploration cost	532		441		6,443		—		7,416
Capitalized interest	50		23		335		482		890
Total	$	1,545	$	464	$	6,778	$	9,760	$	18,547

Standardized Measure of Discounted Future Net Cash Flows

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):



	2016			2015			2014
Future cash inflows	$	246,221		$	295,173		$	675,973
Future production costs	(166,248		)	(146,552		)	(245,180		)
Future development costs, including plugging and abandonment	(18,333		)	(24,833		)	(45,123		)
Future income tax expense	—			—			(29,523		)
Future net cash flows	61,640			123,788			356,147
10% annual discount for estimated timing of cash flows	(26,574		)	(44,760		)	(173,125		)
Standardized measure of discounted future net cash flows	$	35,066		$	79,028		$	183,022

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):



	2016			2015			2014
Standardized measure - beginning of year	$	79,028		$	183,022		$	159,425
Sales and transfers of oil and gas produced, net of production costs	(4,314		)	(29,948		)	(32,139		)
Net changes in prices and production costs	(32,698		)	(127,199		)	(28,544		)
Extensions, discoveries and improved recovery, less related costs	—			15,718			17,582
Changes in future development costs	1,825			(7,387		)	3,195
Development costs incurred during the period	—			27,211			2,079
Revisions of previous quantity estimates	(7,477		)	(6,941		)	23,722
Accretion of discount	7,903			18,870			18,437
Net change in income taxes	—			5,682			19,265
Purchases of reserves	—			—			—
Sales of reserves	(9,201		)	—			—
Standardized measure - end of year	$	35,066		$	79,028		$	183,022

Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications are generally made at the well level each year through the reserve review process. These production profile modifications are based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments are reviewed each year and are often modified in response to current market conditions for items such as permitting and service availability.

Quarterly Historical Data (Unaudited):

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited)

QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2016 and 2015.



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2016
Revenue	$	449,959	$	325,441	$	333,786	$	463,788
Operating income(loss)	$	73,590	$	35,298	$	58,409	$	55,289
Net Income (loss)	$	40,050	$	3,283	$	17,884	$	21,414
Net income (loss) available for common stock	$	40,002	$	669	$	14,131	$	18,168

Earnings (loss) per share - Basic	$	0.78	$	0.01	$	0.27	$	0.34

Earnings (loss) per share - Diluted	$	0.77	$	0.01	$	0.26	$	0.33

Dividends paid per share	$	0.420	$	0.420	$	0.420	$	0.420

Common stock prices - High	$	61.13	$	63.53	$	64.58	$	62.83
Common stock prices - Low	$	44.65	$	56.16	$	56.86	$	54.76

All quarters of 2016 included non-cash impairments of oil and gas properties and external incremental acquisition and transaction costs. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter.



	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2015
Revenue	$	441,987	$	272,254		$	272,105		$	318,259
Operating income (loss)	$	70,500	$	(38,858	)	$	(2,044	)	$	197
Net Income (loss)	$	33,850	$	(41,842	)	$	(9,943	)	$	(14,176	)
Net income (loss) available for common stock	$	33,850	$	(41,842	)	$	(9,943	)	$	(14,176	)

Earnings (loss) per share - Basic	$	0.76	$	(0.94	)	$	(0.22	)	$	(0.30	)

Earnings (loss) per share - Diluted	$	0.76	$	(0.94	)	$	(0.22	)	$	(0.30	)

Dividends paid per share	$	0.405	$	0.405		$	0.405		$	0.405

Common stock prices - High	$	53.37	$	52.96		$	47.27		$	47.51
Common stock prices - Low	$	47.88	$	43.48		$	36.81		$	40.00

All quarters of 2015 included non-cash impairments of oil and gas properties. We incurred external incremental acquisition and transaction costs during the second, third and fourth quarters. We recorded after-tax impairments of oil and gas properties of $14 million during the first quarter, $66 million during the second quarter, $36 million during the third quarter and $44 million during the fourth quarter. We incurred after-tax external incremental acquisition and transaction expenses of $0.5 million during the second quarter, $2.8 million during the third quarter and $3.7 million during the fourth quarter.

Subsequent Event:	12 Months Ended
Subsequent Event:	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS None.

Schedule II Consolidated Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2016

Valuation and Qualifying Accounts [Abstract]

Schedule II Consolidated Valuation and Qualifying Accounts

SCHEDULE II



BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2016, 2015 AND 2014

Description	Balance at Beginning of Year		Adjustments ^(a)		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions			Balance at End of Year
	(in thousands)
Allowance for doubtful accounts:
2016	$	1,741	$	2,158	$	2,704	$	4,915	$	(9,126	)	$	2,392
2015	$	1,516	$	—	$	3,860	$	4,132	$	(7,767	)	$	1,741
2014	$	1,237	$	—	$	4,470	$	4,233	$	(8,424	)	$	1,516

Business Description (Policies)	12 Months Ended
Business Description (Policies)	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business Description	Business Description Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Mining, and Oil and Gas. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Prior to 2016, our segments were reported within two business groups, our Utilities Group, containing the Electric Utilities and Gas Utilities segments, and our Non-regulated Energy Group, containing the Power Generation, Mining and Oil and Gas segments. We have continued to report our operations consistently through our reportable segments. However, we will no longer separate the segments by business group. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities, other than the Oil and Gas segment. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Our Oil and Gas segment, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California. Our Oil and Gas segment’s focus is on cost of service gas programs. We are divesting non-core oil and gas assets while retaining those best suited for a cost of service gas program and have refocused our professional staff on assisting our utilities with the implementation of a Cost of Service Gas Program.
Reclassifications	Revisions Certain revisions have been made to prior years’ financial information to conform to the current year presentation. The Company revised its presentation of cash and book overdrafts. For accounts with the same financial institution where there is a banking arrangement that clears payments with balances in other bank accounts, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Prior year amounts were corrected to conform with the current year presentation, which decreased cash and cash equivalents and accounts payable by $16 million, $12 million and $3.8 million as of December 31, 2015, December 31, 2014 and December 31, 2013, respectively, and decreased net cash flows provided by operations by $3.7 million and $8.1 million for the years ended December 31, 2015 and 2014 respectively. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the consolidated balance sheet as of December 31, 2015 and to the consolidated statements of cash flows for the years ended December 31, 2015 and 2014. There is no impact to the Consolidated Statements of Income (Loss), the Consolidated Statements of Comprehensive Income (Loss) or the Consolidated Statements of Equity, for any period reported.
Use of Estimates and Basis of Presentation	Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 5. Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information.
Variable Interest Entity	Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIEs most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether it qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE.
Cash and Cash Equivalents, Restricted Cash and Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining, Oil and Gas, and Power Generation business segments consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Revenue Recognition	Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers is recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. Our Oil and Gas segment records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.
Materials, Supplies and Fuel	Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.
Property, Plant and Equipment	Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various class of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.
Oil and Gas Operations	Oil and Gas Operations We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement, which varies in length. Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded non-cash ceiling test impairments of oil and gas long-lived assets included in the Oil and Gas segment in 2016 and 2015. No ceiling test write-down was recorded in 2014. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We have no PUDs at December 31, 2016. See information on our oil and gas drilling activities in Note 21. Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report these additional reserve categories.
Goodwill and Intangible Assets	Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity; both are in the fourth quarter of the year, and our current testing date is within ten months of the most recent impairment testing. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results.
Asset Retirement Obligations	Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method.
Fair Value Measurements	Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, or if they qualify for certain exemptions, including the normal purchases and normal sales exemption. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Accounting standards for derivatives and hedging require that the unrealized gains or losses on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting unrealized gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings. Revenues and expenses on contracts that qualify are designated as normal purchases and normal sales and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.
Derivatives, Offsetting Fair Value Amounts	We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs are amortized using the effective interest method over the estimated useful life of the related debt.
Development Costs	Development Costs According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income (Loss).
Legal Costs	Legal Costs Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.
Regulatory Accounting	Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which would require these net assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.
Income Taxes	Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that generated the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets.
Earnings per Share of Common Stock	Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, and outstanding stock options, restricted stock and performance shares under our equity compensation plans.
Business Combinations	Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates.
Noncontrolling Interest	Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income.
Share-Based Compensation	Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.
Recently Issued and Adopted Accounting Standards	Recently Issued and Adopted Accounting Standards Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected. Recently Issued and Adopted Accounting Standards Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). 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 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We will adopt this standard for fiscal years, and interim periods within those years, beginning after December 15, 2016. The adoption of this standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with terms of more than 12 months. Lessees are permitted to make an accounting policy election to not recognize the asset and liability for leases with a term of 12 months or less. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. In addition, the ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which includes a number of practical expedients. The guidance is effective for the Company beginning after December 15, 2018. Early adoption is permitted. We are currently assessing the impact that adoption of ASU 2016-02 will have on our financial position, results of operations or cash flows. Simplifying the Accounting for Measurement-Period Adjustments, ASU 2015-16 In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. This ASU eliminates the requirement to retrospectively account for changes to provisional amounts recognized at the acquisition date in a business combination. ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustments are determined, including the effect of the change in the provisional amount as if the accounting had been completed at the acquisition date. The provisions of this ASU are effective for fiscal years beginning after December 31, 2015, including interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We have implemented ASU 2015-16 as of January 1, 2016. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent), ASU 2015-07 On May 1, 2015, the FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent). The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and were applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU did not materially affect our financial statements and disclosures, but did change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented. Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. We adopted ASU 2015-03 in the first quarter of 2016 on a retrospective basis. As of December 31, 2016, we presented the debt issuance costs, previously reported in other assets, as direct deductions from the carrying amount of long-term debt. The implementation of this standard resulted in reductions of other assets, non-current and long-term debt of $13 million in the Consolidated Balance Sheets as of December 31, 2015. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We will adopt this standard for annual and interim reporting periods beginning after December 15, 2017 and are actively assessing all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that the revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect that there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. However, a number of industry-specific implementation issues are still unresolved and the final resolution of these issues could impact our current accounting policies and/or patterns for revenue recognition, as well as the transition method selected.

Business Description (Tables)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Reclassifications



	Year Ended December 31, 2015							Year Ended December 31, 2014
(in thousands)	As Previously Reported		Presentation Reclassification			As Currently Reported		As Previously Reported		Presentation Reclassification			As Currently Reported
Revenue:
Utilities	$	1,219,526	$	(1,219,526	)	$	—	$	1,300,969	$	(1,300,969	)	$	—
Non-regulated energy	$	85,079	$	(85,079	)	$	—	$	92,601	$	(92,601	)	$	—
Revenue	$	—	$	1,304,605		$	1,304,605	$	—	$	1,393,570		$	1,393,570

Operating Expenses:
Utilities - operations and maintenance	$	272,407	$	(272,407	)	$	—	$	270,954	$	(270,954	)	$	—
Non-regulated energy operations and maintenance	$	88,702	$	(88,702	)	$	—	$	88,141	$	(88,141	)	$	—
Operations and maintenance	$	—	$	361,109		$	361,109	$	—	$	359,095		$	359,095

Accounts Receivable and Allowance for Doubtful Accounts

Following is a summary of accounts receivable as of December 31 (in thousands):



2016	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	41,730	$	36,463	$	(353	)	$	77,840
Gas Utilities	88,168		88,329		(2,026		)	174,471
Power Generation	1,420		—		—			1,420
Mining	3,352		—		—			3,352
Oil and Gas	3,991		—		(13		)	3,978
Corporate	2,228		—		—			2,228
Total	$	140,889	$	124,792	$	(2,392	)	$	263,289



2015	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities ^(a)	$	41,679	$	35,874	$	(727	)	$	76,826
Gas Utilities ^(a)	30,330		32,869		(1,001		)	62,198
Power Generation	1,187		—		—			1,187
Mining	2,760		—		—			2,760
Oil and Gas	3,502		—		(13		)	3,489
Corporate	1,026		—		—			1,026
Total	$	80,484	$	68,743	$	(1,741	)	$	147,486

________________

(a)

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands):



	December 31, 2016		December 31, 2015
Materials and supplies	$	68,456	$	55,726
Fuel - Electric Utilities	3,667		5,567
Natural gas in storage	35,087		25,650
Total materials, supplies and fuel	$	107,210	$	86,943

Schedule of Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands):



	December 31, 2016		December 31, 2015
Accrued employee compensation, benefits and withholdings	$	56,926	$	43,342
Accrued property taxes	40,004		32,393
Accrued payments related to litigation expenses and settlements	—		38,750
Customer deposits and prepayments	51,628		53,496
Accrued interest and contract adjustment payments	45,503		25,762
Other (none of which is individually significant)	49,973		38,318
Total accrued liabilities	$	244,034	$	232,061

Goodwill

Goodwill balances were as follows (in thousands):



	Electric Utilities ^(a)		Gas Utilities ^(a)		Power Generation		Total
Ending balance at December 31, 2014	$	248,479	$	96,152	$	8,765	$	353,396
Additions ^(b)	—		6,363		—		6,363
Ending balance at December 31, 2015	$	248,479	$	102,515	$	8,765	$	359,759
Additions ^(c)	—		939,695		—		939,695
Ending balance at December 31, 2016	$	248,479	$	1,042,210	$	8,765	$	1,299,454

_________________


(a)	Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details.


(b)	Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc.


(c)	Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

Intangible Assets

Changes to intangible assets for the years ended December 31, were as follows (in thousands):



	2016			2015			2014
Intangible assets, net, beginning balance	$	3,380		$	3,176		$	3,397
Additions	5,522			434			—
Amortization expense ^(a)	(510		)	(230		)	(221		)
Intangible assets, net, ending balance	$	8,392		$	3,380		$	3,176

_________________


(a)	Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.

Regulatory Assets and Liabilities

We had the following regulatory assets and liabilities (in thousands):



	Maximum
	Amortization	As of		As of
	(in years)	December 31, 2016		December 31, 2015
Regulatory assets
Deferred energy and fuel cost adjustments - current^(a)(d)	1	$	17,491	$	24,751
Deferred gas cost adjustments^(a)(d)	1	15,329		15,521
Gas price derivatives ^(a)	4	8,843		23,583
Deferred taxes on AFUDC^(b)	45	15,227		12,870
Employee benefit plans ^{(c) (e)}	12	108,556		83,986
Environmental^(a)	subject to approval	1,108		1,180
Asset retirement obligations^(a)	44	505		457
Loss on reacquired debt ^(a)	22	20,188		3,133
Renewable energy standard adjustment ^(a)	5	1,605		5,068
Deferred taxes on flow through accounting^(c)	35	37,498		29,722
Decommissioning costs ^(b)	10	16,859		18,310
Gas supply contract termination ^(a)	5	26,666		—
Other regulatory assets^(a)	15	26,267		13,903
		$	296,142	$	232,484

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	10,368	$	7,814
Employee benefit plans^(c)	12	68,654		47,218
Cost of removal^(a)	44	118,410		90,045
Other regulatory liabilities^(c)	25	9,324		7,964
		$	206,756	$	153,041

__________


(a)	Recovery of costs, but we are not allowed a rate of return.


(b)	In addition to recovery of costs, we are allowed a rate of return.


(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d)


(e)	Increase compared to 2015 was driven by the addition of the SourceGas employee benefit plans.

Earnings Per Share Reconciliation

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):



	December 31, 2016		December 31, 2015			December 31, 2014

Net income (loss) available for common stock	$	72,970	$	(32,111	)	$	130,889

Weighted average shares - basic	51,922		45,288			44,394
Dilutive effect of:
Equity Units	1,222		—			—
Equity compensation	127		—			204
Weighted average shares - diluted	53,271		45,288			44,598

Net income (loss) available for common stock, per share - Diluted	$	1.37	$	(0.71	)	$	2.93

Antidilutive Securities

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):



	December 31, 2016	December 31, 2015	December 31, 2014

Equity compensation	3	112	81
Equity units	—	6,440	—
Anti-dilutive shares excluded from computation of earnings (loss) per share	3	6,552	81

Acquisition: Acquisition (Tables)

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Business Combination, Separately Recognized Transactions



	(in thousands)
Purchase Price	$	1,894,882
Less: Long-term debt assumed	(760,000		)
Less: Working capital adjustment received	(10,644		)
Consideration Paid, net of working capital adjustment received	$	1,124,238

Allocation of Purchase Price:
Current Assets	$	112,983
Property, plant & equipment, net	1,058,093
Goodwill	939,695
Deferred charges and other assets, excluding goodwill	133,299
Current liabilities	(172,454		)
Long-term debt	(758,874		)
Deferred credits and other liabilities	(188,504		)
Total consideration paid, net of working-capital adjustment received	$	1,124,238

Business Acquisition, Pro Forma Information [Table Text Block]

The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015:



	Pro Forma Results
	December 31,
	2016		2015
	(in thousands, except per share amounts)
Revenue	$	1,651,936	$	1,763,901
Net income (loss) available for common stock	$	112,878	$	(13,369	)
Earnings (loss) per share, Basic	$	2.17	$	(0.26	)
Earnings (loss) per share, Diluted	$	2.12	$	(0.26	)

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):



	2016			2015			Lives (in years)
Electric Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Electric plant:
Production	$	1,303,101	41	$	1,136,847	43	30	63
Electric transmission	354,801		52	280,257		50	40	70
Electric distribution	712,575		48	699,775		47	15	75
Plant acquisition adjustment ^(a)	4,870		32	4,870		32	32	32
General	164,761		25	159,496		24	3	65
Capital lease - plant in service ^(b)	261,441		20	261,441		20	20	20
Total electric plant in service	2,801,549			2,542,686
Construction work in progress	74,045			96,501
Total electric plant	2,875,594			2,639,187
Less accumulated depreciation and amortization	578,162			526,954
Electric plant net of accumulated depreciation and amortization ^(c)	$	2,297,432		$	2,112,233

_____________


(a)	The plant acquisition adjustment is included in rate base and is being recovered with 14 years remaining.


(b)	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.


(c)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.



	2016			2015			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	10,821	35	$	13	30	17	71
Gas transmission	338,729		48	45,104		60	22	70
Gas distribution	1,303,366		42	692,800		45	33	47
Cushion gas - depreciable ^(a)	3,539		28	—		0	28	28
Cushion gas - not depreciated ^(a)	47,055		0	—		0	0	0
Storage	27,686		31	—		0	15	48
General	339,382		19	122,109		22	3	44
Total gas plant in service	2,070,578			860,026
Construction work in progress	28,446			11,854
Total gas plant	2,099,024			871,880
Less accumulated depreciation and amortization	194,585			120,458
Gas plant net of accumulated depreciation and amortization ^(b)	$	1,904,439		$	751,422

_____________


(a)	Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.



2016											Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	161,430	$	1,298	$	162,728	$	55,157	$	107,571	33	2	40
Mining	151,709		4,642		156,351		105,219		51,132		13	2	59
Oil and Gas ^(a)	1,101,106		—		1,101,106		1,016,226		84,880		25	2	25

_____________


(a)	Net Property, Plant and Equipment includes full cost pool net assets of approximately $43 million.



2015											Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	156,721	$	2,182	$	158,903	$	51,471	$	107,432	33	2	40
Mining	154,630		3,649		158,279		97,663		60,616		13	2	59
Oil and Gas	1,132,776		—		1,132,776		925,908		206,868		24	3	25



2016												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	5,446	$	11,974	$	17,420	$	(6,115	)	$	23,535	8	3	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.



2015												Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Total Property Plant and Equipment		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	376	$	15,377	$	15,753	$	(4,770	)	$	20,523	10	5	30

___________


(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.

Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Jointly Owned Utility Plants

At December 31, 2016, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	113,611	$	256	$	55,878
Transmission Tie	$	19,978	$	13	$	5,793
Wygen I	$	109,412	$	957	$	37,156
Wygen III	$	138,261	$	1,806	$	17,635
Busch Ranch Wind Farm	$	18,899	$	—	$	3,102

Business Segments Information (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting Information, Additional Information [Abstract]

Segment information included in Consolidated Balance Sheets

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of December 31,	2016		2015
Electric ^{(a) (d)}	$	2,859,559	$	2,704,330
Gas ^{(b) (d)}	3,307,967		999,778
Power Generation^(a)	73,445		60,864
Mining	67,347		76,358
Oil and Gas	96,435		208,956
Corporate ^(c)	110,691		576,357
Total assets	$	6,515,444	$	4,626,643

__________________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


(b)	Includes the assets acquired in the SourceGas acquisition on February 12, 2016.


(c)	Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition.


(d)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million, previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment.



Capital Expenditures and Asset Acquisitions ^(a) for the years ended December 31,	2016		2015
Capital Expenditures
Electric Utilities ^(b)	$	258,739	$	171,897
Gas Utilities^(b)	173,930		99,674
Power Generation	4,719		2,694
Mining	5,709		5,767
Oil and Gas	6,669		168,925
Corporate	17,353		9,864
Total Capital Expenditures	467,119		458,821
Asset Acquisitions
Gas Utilities^{(b) (c)}	1,124,238		21,970
Total Capital Expenditures and Asset Acquisitions	$	1,591,357	$	480,791

_________________


(a)	Includes accruals for property, plant and equipment.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.


(c)	SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2. The 2015 acquisitions represent two acquisitions made by Wyoming Gas.



Property, Plant and Equipment as of December 31,	2016		2015
Electric Utilities ^{(a) (b)}	$	2,875,594	$	2,639,187
Gas Utilities ^{(b) (c)}	2,099,024		871,880
Power Generation ^(a)	162,728		158,903
Mining	156,351		158,279
Oil and Gas	1,101,106		1,132,776
Corporate	17,420		15,753
Total property, plant and equipment	$	6,412,223	$	4,976,778

_______________


(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility Property, Plant and Equipment of $130 million, previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.


(c)	Includes Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016.

Segment information included in Consolidated Statements of Income



	Consolidating Income Statement
Year ended December 31, 2016	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	664,330		$	838,343		$	7,176		$	29,067		$	34,058		$	—		$	—		$	1,572,974
Inter-company revenue	12,951			—			83,955			31,213			—			347,500			(475,619		)	—
Total revenue	677,281			838,343			91,131			60,280			34,058			347,500			(475,619		)	1,572,974

Fuel, purchased power and cost of natural gas sold	261,349			352,165			—			—			—			456			(114,838		)	499,132
Operations and maintenance	158,134			245,826			32,636			39,576			32,158			373,773			(326,847		)	555,256
Depreciation, depletion and amortization	84,645			78,335			4,104			9,346			13,902			22,538			(23,827		)	189,043
Impairment of long-lived assets^(a)	—			—			—			—			106,957			—			—			106,957
Operating income (loss)	173,153			162,017			54,391			11,358			(118,959		)	(49,267		)	(10,107		)	222,586

Interest expense	(56,237		)	(76,586		)	(3,758		)	(401		)	(4,864		)	(109,035		)	115,469			(135,412		)
Interest income	5,946			1,573			1,983			24			—			97,147			(105,244		)	1,429
Other income (expense), net	3,193			184			2			2,209			110			179,839			(181,034		)	4,503
Income tax benefit (expense)	(40,228		)	(27,462		)	(17,129		)	(3,137		)	52,659			24,365			457			(10,475		)
Net income (loss)	85,827			59,726			35,489			10,053			(71,054		)	143,049			(180,459		)	82,631
Net income attributable to noncontrolling interest	—			(102		)	(9,559		)	—			—			—			—			(9,661		)
Net income (loss) available for common stock	$	85,827		$	59,624		$	25,930		$	10,053		$	(71,054	)	$	143,049		$	(180,459	)	$	72,970

________________


(a)	Oil and Gas includes oil and gas property impairments (see Note 13).



	Consolidating Income Statement
Year ended December 31, 2015	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	668,226		$	551,300		$	7,483		$	34,313		$	43,283		$	—		$	—		$	1,304,605
Inter-company revenue	11,617			—			83,307			30,753			—			227,708			(353,385		)	—
Total revenue	679,843			551,300			90,790			65,066			43,283			227,708			(353,385		)	1,304,605

Fuel, purchased power and cost of natural gas sold	269,409			299,645			—			—			—			122			(112,289		)	456,887
Operations and maintenance	160,924			140,723			32,140			41,630			41,593			225,721			(229,786		)	412,945
Depreciation, depletion and amortization	80,929			32,326			4,329			9,806			29,287			9,273			(10,580		)	155,370
Impairment of long-lived assets^(a)	—			—			—			—			249,608			—			—			249,608
Operating income (loss)	168,581			78,606			54,321			13,630			(277,205		)	(7,408		)	(730		)	29,795

Interest expense	(55,159		)	(17,912		)	(4,218		)	(433		)	(2,726		)	(57,839		)	54,568			(83,719		)
Interest income	4,114			601			1,015			34			217			48,582			(52,942		)	1,621
Other income (expense), net	1,216			315			71			2,247			(337		)	70,889			(71,964		)	2,437
Impairment of equity investments ^(a)	—			—			—			—			(4,405		)	—			—			(4,405		)
Income tax benefit (expense)	(41,173		)	(22,304		)	(18,539		)	(3,608		)	104,498			2,926			360			22,160
Net income (loss)	77,579			39,306			32,650			11,870			(179,958		)	57,150			(70,708		)	(32,111		)
Net income attributable to noncontrolling interest	—			—			—			—			—			—			—			—
Net income (loss) available for common stock	$	77,579		$	39,306		$	32,650		$	11,870		$	(179,958	)	$	57,150		$	(70,708	)	$	(32,111	)

________________


(a)	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).



	Consolidating Income Statement
Year ended December 31, 2014	Electric Utilities			Gas Utilities			Power Generation			Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	643,446		$	657,523		$	6,401		$	31,086		$	55,114		$	—		$	—		$	1,393,570
Inter-company revenue	14,110			—			81,157			32,272			—			222,460			(349,999		)	—
Total revenue	657,556			657,523			87,558			63,358			55,114			222,460			(349,999		)	1,393,570

Fuel, purchased power and cost of natural gas sold	291,644			403,781			—			—			—			116			(113,759		)	581,782
Operations and maintenance	156,252			142,024			33,126			41,172			42,659			213,415			(225,473		)	403,175
Depreciation, depletion and amortization	77,011			28,912			4,540			10,276			24,246			7,690			(7,930		)	144,745
Operating income (loss)	132,649			82,806			49,892			11,910			(11,791		)	1,239			(2,837		)	263,868

Interest expense	(51,640		)	(17,487		)	(4,351		)	(493		)	(2,603		)	(50,299		)	55,913			(70,960		)
Interest income	4,590			466			682			59			918			48,969			(53,759		)	1,925
Other income (expense), net	1,074			124			(6		)	2,275			183			61,605			(62,574		)	2,681
Income tax benefit (expense)	(29,403		)	(21,758		)	(17,701		)	(3,299		)	4,768			24			744			(66,625		)
Net income (loss)	57,270			44,151			28,516			10,452			(8,525		)	61,538			(62,513		)	130,889
Net income attributable to noncontrolling interest	—			—			—			—			—			—			—			—
Net income (loss) available for common stock	$	57,270		$	44,151		$	28,516		$	10,452		$	(8,525	)	$	61,538		$	(62,513	)	$	130,889

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments

Long-term debt outstanding was as follows (dollars in thousands):



		Interest Rate at
	Due Date	December 31, 2016	December 31, 2016			December 31, 2015
Corporate
Senior unsecured notes due 2023	November 30, 2023	4.25%	$	525,000		$	525,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Corporate term loan due 2017 ^(a)			—			300,000
Remarketable junior subordinated notes ^(b)	November 1, 2028	3.50%	299,000			299,000
Senior unsecured notes due 2019	January 11, 2019	2.50%	250,000			—
Senior unsecured notes due 2026	January 15, 2026	3.95%	300,000			—
Senior unsecured notes due 2027	January 15, 2027	3.15%	400,000			—
Senior unsecured notes, due 2046	September 15, 2046	4.20%	300,000			—
Corporate term loan due 2019 ^(a)	August 9, 2019	1.74%	400,000			—
Corporate term loan due 2021	June 7, 2021	2.32%	24,406			—
Total Corporate Debt			2,698,406			1,324,000
Less unamortized debt discount			(4,413		)	(1,890		)
Total Corporate Debt, Net			2,693,993			1,322,110

Electric Utilities
First Mortgage Bonds due 2044	October 20, 2044	4.43%	85,000			85,000
First Mortgage Bonds due 2044	October 20, 2044	4.53%	75,000			75,000
First Mortgage Bonds due 2032	August 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%	180,000			180,000
First Mortgage Bonds due 2037	November 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021 ^(c)	September 1, 2021	0.72%	7,000			7,000
Industrial development revenue bonds due 2027 ^(c)	March 1, 2027	0.72%	10,000			10,000
Series 94A Debt, variable rate ^(c)	June 1, 2024	0.88%	2,855			2,855
Total Electric Utilities Debt			544,855			544,855
Less unamortized debt discount			(94		)	(99		)
Total Electric Utilities Debt			544,761			544,756

Total long-term debt			3,238,754			1,866,866
Less current maturities			5,743			—
Less deferred financing costs ^(d)			21,822			13,184
Long-term debt, net of current maturities and deferred financing costs			$	3,211,189		$	1,853,682

_______________


(a)	Variable interest rate, based on LIBOR plus a spread.


(b)	See Note 12 for RSN details.


(c)	Variable interest rate.


(d)	Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2016 and December 31, 2015, respectively.

Schedule of Maturities of Long-term Debt

Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):



2017	$	5,743
2018	$	5,743
2019	$	655,742
2020	$	205,742
2021	$	8,436
Thereafter	$	2,361,855

Deferred Financing Costs

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):



	Deferred Financing Costs Remaining at		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616
Senior unsecured notes due 2023	2,921		494		494		653
Senior unsecured notes due 2019	763		643		—		—
Senior unsecured notes due 2020	592		167		167		167
Senior unsecured notes due 2026	2,318		262		—		—
Senior unsecured notes due 2027	3,281		121		—		—
Senior unsecured notes due 2046	3,193		37		—		—
Corporate term loan due 2019	287		144		—		—
Bridge Term Loan	—		843		4,213		—
RSNs due 2028	1,449		122		10		—
First mortgage bonds due 2044 (South Dakota Electric)	663		24		24		6
First mortgage bonds due 2044 (Wyoming Electric)	613		23		22		6
First mortgage bonds due 2032	518		33		33		33
First mortgage bonds due 2039	1,734		76		76		76
First mortgage bonds due 2037	643		31		31		31
Other	506		304		43		53
Total	$	21,822	$	3,861	$	5,617	$	1,641

The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Notes Payable (Tables)

12 Months Ended

Dec. 31, 2016

Notes Payable [Abstract]

Schedule of Short-term Debt

We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):

Deferred Financing Costs

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):



	Deferred Financing Costs Remaining at		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616
Senior unsecured notes due 2023	2,921		494		494		653
Senior unsecured notes due 2019	763		643		—		—
Senior unsecured notes due 2020	592		167		167		167
Senior unsecured notes due 2026	2,318		262		—		—
Senior unsecured notes due 2027	3,281		121		—		—
Senior unsecured notes due 2046	3,193		37		—		—
Corporate term loan due 2019	287		144		—		—
Bridge Term Loan	—		843		4,213		—
RSNs due 2028	1,449		122		10		—
First mortgage bonds due 2044 (South Dakota Electric)	663		24		24		6
First mortgage bonds due 2044 (Wyoming Electric)	613		23		22		6
First mortgage bonds due 2032	518		33		33		33
First mortgage bonds due 2039	1,734		76		76		76
First mortgage bonds due 2037	643		31		31		31
Other	506		304		43		53
Total	$	21,822	$	3,861	$	5,617	$	1,641

The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended December 31,
	December 31, 2016		2016		2015		2014
Revolving Credit Facility	$	2,341	$	537	$	504	$	616

Schedule of Credit Facility Covenants

Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):



	December 31, 2015		Liabilities Incurred		Liabilities Settled			Accretion		Liabilities Acquired ^(a)		Revisions to Prior Estimates^(b)(c)			December 31, 2016
Electric Utilities	$	4,462	$	—	$	—		$	191	$	—	$	8		$	4,661
Gas Utilities	136		—		—			791		22,412		6,436			29,775
Mining	18,633		—		(105		)	822		—		(6,910		)	12,440
Oil and Gas	21,504		3		(2,049		)	1,382		—		1,923			22,763
Total	$	44,735	$	3	$	(2,154	)	$	3,186	$	22,412	$	1,457		$	69,639



	December 31, 2014		Liabilities Incurred		Liabilities Settled			Accretion		Liabilities Acquired		Revisions to Prior Estimates^(c)			December 31, 2015
Electric Utilities	$	7,012	$	—	$	(2,733	)	$	183	$	—	$	—		$	4,462
Gas Utilities	291		—		(168		)	13		—		—			136
Mining	19,138		—		—			993		—		(1,498		)	18,633
Oil and Gas	20,945		828		(1,792		)	1,371		—		152			21,504
Total	$	47,386	$	828	$	(4,693	)	$	2,560	$	—	$	(1,346	)	$	44,735

_____________________


(a)	Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas.


(b)	The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.


(c)	The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. The 2015 Mining Revision to Prior Estimates reflects a change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.

Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative [Line Items]

Schedule of Derivative Instruments

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



	December 31, 2016			December 31, 2015
	Interest Rate Swaps ^(a)			Interest Rate Swaps ^(a)			Interest Rate Swaps ^(b)
Notional	$	50,000		$	75,000		$	250,000
Weighted average fixed interest rate	4.94		%	4.97		%	2.29		%
Maximum terms in months	1			13			16
Derivative assets, non-current	$	—		$	—		$	3,441
Derivative liabilities, current	$	90		$	2,835		$	—
Derivative liabilities, non-current	$	—		$	156		$	—

___________________


(a)	The $25 million in swaps expired in October 2016 and the $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.


(b)	These swaps were settled on August 19, 2016.

Contract or notional amounts and terms of marketing activities and derivative commodity instruments



	December 31, 2016		December 31, 2015
	Notional (MMBtus)	Maximum Term (months) ^(a)	Notional (MMBtus)	Maximum Term (months) ^(a)
Natural gas futures purchased	14,770,000	48	20,580,000	60
Natural gas options purchased, net ^(b)	3,020,000	5	2,620,000	3
Natural gas basis swaps purchased	12,250,000	48	18,150,000	60
Natural gas over-the-counter swaps, net ^(c)	4,622,302	28	—	0
Natural gas physical commitments, net ^(d)	21,504,378	10	—	0

__________


(a)	Term reflects the maximum forward period hedged.


(b)	Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions.


(c)	As of December 31, 2016, 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.


(d)	Volumes exclude contracts that qualify for normal purchase, normal sales exception.

Derivative Instruments, Gain (Loss)



	December 31, 2016
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,899	)	Interest expense	$	(953	)
Commodity derivatives	Revenue	11,019				—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	(14		)		—
Total impact from cash flow hedges		$	7,106			$	(953	)



	December 31, 2015
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,647	)		$	—
Commodity derivatives	Revenue	14,460				—
Total		$	10,813			$	—



	December 31, 2014
Derivatives in Cash Flow Hedging Relationships	Location of Reclassifications from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	Interest expense	$	(3,669	)		$	—
Commodity derivatives	Revenue	(1,995		)		—
Total		$	(5,664	)		$	—



	December 31, 2016			December 31, 2015			December 31, 2014
	(In thousands)
Increase (decrease) in fair value:
Interest rate swaps	$	(31,222	)	$	2,888		$	(536	)
Forward commodity contracts	(573		)	9,782			14,681
Recognition of (gains) losses in earnings due to settlements:
Interest rate swaps	3,899			3,647			3,669
Forward commodity contracts	(11,005		)	(14,460		)	1,995
Total other comprehensive income (loss) from hedging	$	(38,901	)	$	1,857		$	19,809

Derivatives Not Designated as Hedge Instruments



		2016			2015		2014
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income			Amount of Gain/(Loss) on Derivatives Recognized in Income		Amount of Gain/(Loss) on Derivatives Recognized in Income

Commodity derivatives	Revenue	$	(50	)	$	—	$	—
Commodity derivatives	Fuel, purchased power and cost of natural gas sold	940			—		—
		$	890		$	—	$	—

Oil and Gas

Derivative [Line Items]

Schedule of Derivative Instruments



	December 31, 2016			December 31, 2015
	Crude oil futures and swaps ^(b)	Crude oil options	Natural gas futures and swaps ^(b)	Crude oil futures and swaps ^(b)	Natural gas futures and swaps ^(b)
Notional ^(a)	108,000	36,000	2,700,000	198,000	4,392,500
Maximum terms in months ^(c)	24	12	24	24	24

________________________


(a)	Crude in Bbls, gas in MMBtus.


(b)	These financial instruments were designated as cash flow hedges upon inception.


(c)	Refers to the maximum forward period hedged.

- 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

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-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):



	As of December 31, 2016
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	2,886	$	—	$	(2,733	)	$	153
Commodity derivatives - Utilities	—		7,469		—		(3,262		)	4,207
Interest rate swaps	—		—		—		—			—
Total	$	—	$	10,355	$	—	$	(5,995	)	$	4,360

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	1,586	$	—	$	—		$	1,586
Commodity derivatives - Utilities	—		12,201		—		(11,144		)	1,057
Interest rate swaps	—		90		—		—			90
Total	$	—	$	13,877	$	—	$	(11,144	)	$	2,733



	As of December 31, 2015
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,644	$	—	$	(10,644	)	$	—
Commodity derivatives - Utilities	—		2,293		—		(2,293		)	—
Interest rate swaps	—		3,441		—		—			3,441
Total	$	—	$	16,378	$	—	$	(12,937	)	$	3,441

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	556	$	—	$	(556	)	$	—
Commodity derivatives - Utilities	—		24,585		—		(24,585		)	—
Interest rate swaps	—		2,991		—		—			2,991
Total	$	—	$	28,132	$	—	$	(25,141	)	$	2,991

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):



		2016				2015
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets - current	$	1,161	$	—	$	9,981	$	—
Commodity derivatives	Derivative assets - non-current	124		—		663		—
Interest rate swaps	Derivative assets - non-current	—		—		3,441		—
Commodity derivatives	Derivative liabilities - current	—		1,090		—		465
Commodity derivatives	Derivative liabilities - non-current	—		238		—		91
Interest rate swaps	Derivative liabilities - current	—		90		—		2,835
Interest rate swaps	Derivative liabilities - non-current	—		—		—		156
Total derivatives designated as hedges		$	1,285	$	1,418	$	14,085	$	3,547

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	2,977	$	—	$	—	$	—
Commodity derivatives	Derivative assets - non-current	98		—		—		—
Commodity derivatives	Derivative liabilities - current	—		1,279		—		9,586
Commodity derivatives	Derivative liabilities - non-current	—		36		—		12,706
Interest rate swaps	Derivative liabilities - current	—		—		—		—
Interest rate swaps	Derivative liabilities - non-current	—		—		—		—
Total derivatives not designated as hedges		$	3,075	$	1,315	$	—	$	22,292

Schedule of Derivative Offsetting on Balance Sheet

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2016 was as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	2,886	$	(2,733	)	$	153
Utilities	4,269		(3,262		)	1,007
Interest Rate Swaps	—		—			—
Total derivative assets subject to a master netting agreement or similar arrangement	7,155		(5,995		)	1,160

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	3,200		—			3,200
Interest rate swaps	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	3,200		—			3,200

Total derivative assets	$	10,355	$	(5,995	)	$	4,360



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	1,586	$	—		$	1,586
Utilities	11,144		(11,144		)	—
Interest Rate Swaps	—		—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	12,730		(11,144		)	1,586

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	1,057		—			1,057
Interest Rate Swaps	90		—			90
Total derivative liabilities not subject to a master netting agreement or similar arrangement	1,147		—			1,147

Total derivative liabilities	$	13,877	$	(11,144	)	$	2,733

Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2015 were as follows (in thousands):



Derivative Assets	Gross Amounts of Derivative Assets		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Assets on Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	10,644	$	(10,644	)	$	—
Utilities	2,293		(2,293		)	—
Interest rate swaps	3,441		—			3,441
Total derivative assets subject to a master netting agreement or similar arrangement	16,378		(12,937		)	3,441

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	—		—			—
Interest rate swaps	—		—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	—		—			—

Total derivative assets	$	16,378	$	(12,937	)	$	3,441



Derivative Liabilities	Gross Amounts of Derivative Liabilities		Gross Amounts Offset on Consolidated Balance Sheets			Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	$	556	$	(556	)	$	—
Utilities	24,585		(24,585		)	—
Interest Rate Swaps	2,991		—			2,991
Total derivative liabilities subject to a master netting agreement or similar arrangement	28,132		(25,141		)	2,991

Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas	—		—			—
Utilities	—		—			—
Interest Rate Swaps	—		—			—
Total derivative liabilities not subject to a master netting agreement or similar arrangement	—		—			—

Total derivative liabilities	$	28,132	$	(25,141	)	$	2,991

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair value of financial instruments

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):



	2016				2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	13,580	$	13,580	$	440,861	$	440,861
Restricted cash and equivalents ^(a)	$	2,274	$	2,274	$	1,697	$	1,697
Notes payable ^(b)	$	96,600	$	96,600	$	76,800	$	76,800
Long-term debt, including current maturities ^(c)	$	3,216,932	$	3,351,305	$	1,853,682	$	1,992,274

_______________


(a)	Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy.


(b)	Notes payable consist of borrowings on our Revolving Credit Facility. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.


(c)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Equity: (Tables)

12 Months Ended

Dec. 31, 2016

Stockholders' Equity Note [Abstract]

Schedule of Company's equity units

Selected information about our equity units is presented below (in thousands except for percentages):



Issuance Date	Units Issued	Total Net Proceeds		Total Long-term Debt (RSNs)		RSN Interest Rate (annual)		Stock Purchase Contract Rate (annual)		Stock Purchase Contract Liability as of December 31, 2016
11/23/2015	5,980	$	290,030	$	299,000	3.50	%	4.25	%	$	23,335

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs

Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):



	2016		2015		2014
Stock-based compensation expense	$	10,885	$	4,076	$	9,329

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity

A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands):



	2016		2015
Shares Issued	51		66

Weighted Average Price	$	58.24	$	44.79

Unissued Shares Available	356		408

Schedule of Variable Interest Entities

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:



	2016		2015
	(in thousands)
Assets
Current assets	$	12,627	$	—
Property, plant and equipment of variable interest entities, net	$	218,798	$	—

Liabilities
Current liabilities	$	4,342	$	—

Restricted Stock

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

A summary of the status of the restricted stock and restricted stock units at December 31, 2016, was as follows:



	Restricted Stock		Weighted-Average Grant Date Fair Value
	(in thousands)
Balance at beginning of period	202		$	48.96
Granted	195		53.55
Vested	(88	)	48.00
Forfeited	(14	)	51.89
Balance at end of period	295		$	52.15

Performance Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

Outstanding performance periods at December 31 were as follows (shares in thousands):



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
January 1, 2014	January 1, 2014 - December 31, 2016	44	0%	200%
January 1, 2015	January 1, 2015 - December 31, 2017	43	0%	200%
January 1, 2016	January 1, 2016 - December 31, 2018	53	0%	200%

A summary of the status of the Performance Share Plan at December 31 was as follows:



	Equity Portion				Liability Portion
			Weighted-Average Grant Date Fair Value^(a)				Weighted-Average Fair Value at
	Shares		Weighted-Average Grant Date Fair Value^(a)		Shares		December 31, 2016
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	74		$	47.21	74
Granted	27		47.76		27
Forfeited	—		—		—
Vested	(30	)	35.86		(30	)
Performance Shares balance at end of period	71		$	52.29	71		$	48.05

_____________________


(a)	The grant date fair values for the performance shares granted in 2016, 2015 and 2014 were determined by Monte Carlo simulation using a blended volatility of 24%, 21% and 23%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:



	Weighted Average Grant Date Fair Value
December 31, 2016	$	47.76
December 31, 2015	$	54.92
December 31, 2014	$	55.18

Performance plan payouts have been as follows (dollars and shares in thousands):



Performance Period	Year of Payment	Shares Issued	Cash Paid		Total Intrinsic Value
January 1, 2013 to December 31, 2015	2016	—	$	—	$	—
January 1, 2012 to December 31, 2014	2015	69	$	3,657	$	7,314
January 1, 2011 to December 31, 2013	2014	59	$	3,011	$	6,020

Operating Leases (Tables)

12 Months Ended

Dec. 31, 2016

Leases, Operating [Abstract]

Operating Leases of Lessor Disclosure

Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):



	2016		2015		2014
Rent expense	$	9,568	$	7,177	$	6,932

Schedule of Future Minimum Rental Payments for Operating Leases

The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):



2017	$	6,739
2018	$	5,564
2019	$	4,441
2020	$	2,639
2021	$	1,652
Thereafter	$	6,245

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):



	2016			2015			2014
Current:
Federal	$	(23,820	)	$	2,549		$	(2,319	)
State	(1,922		)	1,319			(1,288		)
	(25,742		)	3,868			(3,607		)
Deferred:
Federal	36,012			(23,592		)	64,780
State	257			(2,323		)	5,658
Tax credit amortization	(52		)	(113		)	(206		)
	36,217			(26,028		)	70,232

	$	10,475		$	(22,160	)	$	66,625

Schedule of Deferred Tax Assets and Liabilities

The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):



	2016			2015
Deferred tax assets:
Regulatory liabilities	$	58,200		$	43,586
Employee benefits	29,638			26,400
Federal net operating loss	252,780			217,922
Other deferred tax assets^(a)	83,485			85,907
Less: Valuation allowance	(9,263		)	(4,304		)
Total deferred tax assets	414,840			369,511

Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences^(b)	(820,111		)	(711,293		)
Regulatory assets	(49,471		)	(29,092		)
State deferred tax liability	(47,987		)	(35,065		)
Deferred costs	(18,551		)	(26,121		)
Other deferred tax liabilities	(14,326		)	(18,519		)
Total deferred tax liabilities	(950,446		)	(820,090		)

Net deferred tax liability	$	(535,606	)	$	(450,579	)

_______________


(a)	Other deferred tax assets consist primarily of state tax credits, state net operating loss, alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.


(b)	To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million, previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration.

Schedule of Effective Income Tax Rate Reconciliation

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:



	2016		2015		2014
Federal statutory rate ^(e)	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	0.2		1.0		1.1
Amortization of excess deferred income taxes and investment tax credits	(0.1	)	0.2		(0.1	)
Percentage depletion^(a)	(8.2	)	3.5		(1.0	)
Non-controlling interest^(d)	(3.6	)	—		—
Equity AFUDC	(1.1	)	0.3		(0.1	)
Tax credits	(1.5	)	0.5		(0.1	)
Transaction costs	1.1		—		—
Accounting for uncertain tax positions adjustment^(b)	(6.0	)	(3.5	)	(0.1	)
Flow-through adjustments^(c)	(5.1	)	3.8		(0.9	)
Other tax differences	0.6		—		(0.1	)
	11.3	%	40.8	%	33.7	%

_________________________


(a)	The tax benefit includes additional percentage depletion deductions that were claimed with respect to the oil and gas properties involving prior tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.

(b)

(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 was not recorded.


(e)	The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net

Summary of Operating Loss Carryforwards

At December 31, 2016, we have federal and gross state NOL carryforwards that will expire at various dates as follows (in thousands):



	Amounts		Expiration Dates
Federal Net Operating Loss Carryforward	$	721,075	2019	to	2036

State Net Operating Loss Carryforward	$	616,524	2017	to	2036

Summary of Income Tax Contingencies



	Changes in Uncertain Tax Positions
Beginning balance at January 1, 2014	$	37,631
Additions for prior year tax positions	1,253
Reductions for prior year tax positions	(6,692		)
Additions for current year tax positions	—
Settlements	—
Ending balance at December 31, 2014	32,192
Additions for prior year tax positions	3,285
Reductions for prior year tax positions	(3,491		)
Additions for current year tax positions	—
Settlements	—
Ending balance at December 31, 2015	31,986
Additions for prior year tax positions	2,423
Reductions for prior year tax positions	(19,174		)
Additions for current year tax positions	—
Settlements	(11,643		)
Ending balance at December 31, 2016	$	3,592

State and Local Jurisdiction

Operating Loss Carryforwards [Line Items]

Summary of State Tax Carryforwards

State tax credits have been generated and are available to offset future state income taxes. At December 31, 2016, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
Investment tax credit	$	19,765	2023	to	2036
Research and development	$	167	No expiration

Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2016

Statement of Comprehensive Income [Abstract]

Reclassification out of Accumulated Other Comprehensive Income

The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):



	Location on the Consolidated Statements of Income (Loss)	Amount Reclassified from AOCI
	Location on the Consolidated Statements of Income (Loss)	December 31, 2016			December 31, 2015
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(3,899	)	$	(3,647	)
Commodity contracts	Revenue	11,019			14,460
Commodity contracts	Fuel, purchased power and cost of natural gas sold	(14		)	—
		7,106			10,813
Income tax	Income tax benefit (expense)	(2,702		)	(4,271		)
Total reclassification adjustments related to cash flow hedges, net of tax		$	4,404		$	6,542

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	221		$	238
Actuarial gain (loss)	Operations and maintenance	(1,978		)	(2,822		)
		(1,757		)	(2,584		)
Income tax	Income tax benefit (expense)	533			884
Total reclassification adjustments related to defined benefit plans, net of tax		$	(1,224	)	$	(1,700	)
Total reclassifications		$	3,180		$	4,842

Schedule of Accumulated Other Comprehensive Income (Loss)

Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2015	$	(341	)	$	7,066		$	(15,780	)	$	(9,055	)
Other comprehensive income (loss)
before reclassifications	(20,302		)	(361		)	(1,985		)	(22,648		)
Amounts reclassified from AOCI	2,534			(6,938		)	1,224			(3,180		)
As of December 31, 2016	$	(18,109	)	$	(233	)	$	(16,541	)	$	(34,883	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2014	$	(4,930	)	$	10,023		$	(20,137	)	$	(15,044	)
Other comprehensive income (loss)
before reclassifications	2,290			5,884			2,657			10,831
Amounts reclassified from AOCI	2,299			(8,841		)	1,700			(4,842		)
As of December 31, 2015	$	(341	)	$	7,066		$	(15,780	)	$	(9,055	)

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information



Years ended December 31,	2016			2015			2014
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	29,082		$	40,250		$	52,584
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	8,577		$	(518	)	$	(5,634	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(112,925	)	$	(77,810	)	$	(69,239	)
Income taxes, net	$	(1,156	)	$	(1,202	)	$	(413	)

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

Defined Benefit Plan Disclosure [Line Items]

Schedule of Defined Benefit Plans Disclosures

Amounts recognized in the Condensed Consolidated Balance Sheets upon the February 12, 2016 acquisition are (in thousands):

Schedule of Allocation of Plan Assets

The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows:



	2016	2015
Equity	28%	26%
Real estate	5	5
Fixed income	57	59
Cash	2	1
Hedge funds	8	9
Total	100%	100%

Schedule of Defined Contribution Plans Contributions

Contributions for the years ended December 31 were as follows (in thousands):



	2016		2015
Defined Contribution Plan
Company Retirement Contribution	$	9,632	$	5,564
Matching contributions	$	9,645	$	9,616



	2016		2015
Defined Benefit Plans
Defined Benefit Pension Plans	$	14,200	$	10,200
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,965	$	3,771
Supplemental Non-Qualified Defined Benefit Plans	$	1,565	$	1,564

Schedule of Changes in Projected Benefit Obligations

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2016			2015			2016			2015			2016			2015
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	356,575		$	377,772		$	40,219		$	41,211		$	48,077		$	49,042
Transfer from SourceGas Acquisition	75,254			—			—			—			15,091			—
Service cost	7,619			6,093			2,099			1,300			1,757			1,808
Interest cost	15,743			15,522			1,257			1,455			1,942			1,801
Actuarial (gain) loss ^(a)	7,001			(28,229		)	2,049			(2,072		)	2,808			(1,206		)
Amendments	—			—			—			—			2,203			—
Benefits paid	(22,013		)	(14,583		)	(1,755		)	(1,675		)	(4,965		)	(3,771		)
Medicare Part D accrued	—			—			—			—			—			(178		)
Plan participants’ contributions	—			—			—			—			1,110			581
Projected benefit obligation at end of year	$	440,179		$	356,575		$	43,869		$	40,219		$	68,023		$	48,077

____________________


(a)	Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates.

Schedule of Changes in Fair Value of Plan Assets



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2016			2015			2016		2015		2016			2015

Beginning fair value of plan assets	$	288,622		$	299,533		$	—	$	—	$	4,681		$	4,705
Transfer from SourceGas Acquisition	53,067			—			—		—		3,340			—
Investment income (loss)	30,819			(6,528		)	—		—		256			(9		)
Employer contributions	14,200			10,200			—		—		4,048			3,175
Retiree contributions	—			—			—		—		1,110			581
Benefits paid	(22,013		)	(14,583		)	—		—		(4,965		)	(3,771		)
Plan administrative expenses	—			—			—		—		—			—
Ending fair value of plan assets	$	364,695		$	288,622		$	—	$	—	$	8,470		$	4,681

____________________


(a)	Assets of VEBAs and Grantor Trust.

Schedule of Amounts Recognized in Balance Sheet

The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016		2015
Regulatory assets	$	66,640	$	68,915	$	—	$	—	$	11,401	$	6,464
Current liabilities	$	—	$	—	$	1,583	$	1,568	$	4,360	$	3,543
Non-current assets	$	—	$	—	$	—	$	—	$	21	$	23
Non-current liabilities	$	75,484	$	67,953	$	42,286	$	38,651	$	55,214	$	39,855
Regulatory liabilities	$	5,195	$	—	$	—	$	—	$	3,419	$	3,209

Schedule of Accumulated and Projected Benefit Obligations

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016		2015
Accumulated Benefit Obligation^(a)	$	416,786	$	334,923	$	32,090	$	30,558	$	68,023	$	48,077

____________________

(a)

Components of net periodic benefit cost

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2016			2015			2014			2016		2015		2014		2016			2015			2014
Service cost	$	7,619		$	6,093		$	5,448		$	1,335	$	1,380	$	1,498	$	1,757		$	1,808		$	1,700
Interest cost	15,743			15,522			15,852			1,257		1,455		1,447		1,942			1,801			1,919
Expected return on assets	(23,062		)	(19,470		)	(18,065		)	—		—		—		(279		)	(131		)	(85		)
Net amortization of prior service cost	58			58			62			2		2		2		(428		)	(428		)	(428		)
Recognized net actuarial loss (gain)	7,173			11,037			4,806			829		1,081		498		335			408			160
Settlement Expense^(a)	10			—			—			—		—		—		—			—			—
Net periodic expense	$	7,541		$	13,240		$	8,103		$	3,423	$	3,918	$	3,445	$	3,327		$	3,458		$	3,266

____________________


(a)	Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.

Schedule of Net Periodic Benefit Cost Not yet Recognized

For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2016		2015		2016		2015		2016			2015
Net (gain) loss	$	8,472	$	8,777	$	7,132	$	6,339	$	1,595		$	1,704
Prior service cost (gain)	31		41		5		6		(694		)	(1,087		)
Total AOCI	$	8,503	$	8,818	$	7,137	$	6,345	$	901		$	617

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	2,604	$	572	$	325
Prior service cost (credit)	38		1		(368		)
Total net periodic benefit cost expected to be recognized during calendar year 2017	$	2,642	$	573	$	(43	)

Schedule of Assumptions Used

Assumptions



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine benefit obligations:	2016		2015		2014		2016		2015		2014		2016		2015		2014

Discount rate	4.27	%	4.58	%	4.19	%	4.02	%	4.28	%	4.19	%	3.96	%	4.17	%	3.82	%
Rate of increase in compensation levels	3.47	%	3.51	%	3.76	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2016		2015		2014		2016		2015		2014		2016		2015		2014

Discount rate ^(a)	4.50	%	4.19	%	5.04	%	4.28	%	4.19	%	5.03	%	4.18	%	3.82	%	4.46	%
Expected long-term rate of return on assets ^(b)	6.87	%	6.75	%	6.75	%	N/A		N/A		N/A		3.83	%	3.00	%	2.00	%
Rate of increase in compensation levels	3.42	%	3.76	%	3.76	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A

_____________________________


(a)	The estimated discount rate for the merged Black Hills Retirement Plan is 4.27% for the calculation of the 2017 net periodic pension costs.


(b)	The expected rate of return on plan assets is 6.75% for the calculation of the 2017 net periodic pension cost.

Schedule of Health Care Cost Trend Rates

The healthcare benefit obligation was determined at December 31 as follows:



	2016 ^(a)	2015
Trend Rate - Medical
Pre-65 for next year - All Plans	6.10%	6.35%
Pre-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2024	2024

Post-65 for next year - All Plans	5.10%	5.20%
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Trend Year	2023	2023

_____________________________


(a)	The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands):



Change in Assumed Trend Rate	Impact on December 31, 2016 Accumulated Postretirement Benefit Obligation			Impact on 2017 Service and Interest Cost
Increase 1%	$	2,569		$	156
Decrease 1%	$	(2,191	)	$	(131	)

Schedule of Expected Benefit Payments

The following benefit payments, which reflect future service, are expected to be paid (in thousands):



	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-Pension Defined Benefit Postretirement Healthcare Plans
2017	$	21,355	$	1,583	$	5,504
2018	$	21,566	$	1,809	$	5,779
2019	$	23,010	$	1,921	$	5,886
2020	$	27,028	$	1,634	$	5,983
2021	$	27,614	$	1,836	$	5,931
2022-2026	$	149,893	$	11,009	$	27,585

Pension Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets

The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):



Defined Benefit Pension Plans	December 31, 2016
	Level 1		Level 2		Level 3		NAV ^(a)		Total
AXA Equitable General Fixed Income	$	—	$	1,325	$	—	—		$	1,325
Common Collective Trust - Cash and Cash Equivalents	—		5,307		—		—		5,307
Common Collective Trust - Equity	—		101,020		—		—		101,020
Common Collective Trust - Fixed Income	—		209,815		—		—		209,815
Common Collective Trust - Real Estate	—		2,349		—		15,563		17,912
Hedge Funds	—		—		—		29,316		29,316
Total investments measured at fair value	$	—	$	319,816	$	—	$	44,879	$	364,695



Defined Benefit Pension Plans	December 31, 2015
	Level 1		Level 2		Level 3		NAV ^(a)		Total
AXA Equitable General Fixed Income	$	—	$	1,072	$	—	$	—	$	1,072
Common Collective Trust - Cash and Cash Equivalents	—		1,556		—		—		1,556
Common Collective Trust - Equity	—		74,885		—		—		74,885
Common Collective Trust - Fixed Income	—		172,016		—		—		172,016
Common Collective Trust - Real Estate	—		2,204		—		11,143		13,347
Hedge Funds	—		—		—		25,746		25,746
Total investments measured at fair value	$	—	$	251,733	$	—	$	36,889	$	288,622

_____________

(a)

Postretirement Health Coverage

Defined Benefit Plan Disclosure [Line Items]

Schedule of Allocation of Plan Assets



Non-pension Defined Benefit Postretirement Healthcare Plans	December 31, 2016
	Level 1		Level 2		Level 3		Total
Cash and Cash Equivalents	$	111	$	—	$	—	$	111
Equity Securities	1,154		—		—		1,154
Registered Investment Company Trust - Money Market Mutual Fund	—		4,732		—		4,732
Intermediate-term Bond	—		2,473		—		2,473
Total investments measured at fair value	$	1,265	$	7,205	$	—	$	8,470



Non-pension Defined Benefit Postretirement Healthcare Plans	December 31, 2015
	Level 1		Level 2		Level 3		Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—	$	4,681	$	—	$	4,681
Total investments measured at fair value	$	—	$	4,681	$	—	$	4,681

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure



	Power Purchase Agreements		Transportation, storage, gathering and coal agreements
2017	$	26,690	$	136,607
2018	$	8,934	$	120,123
2019	$	6,388	$	87,210
2020	$	6,388	$	82,247
2021	$	5,755	$	75,424
Thereafter	$	11,509	$	225,765

Power purchased

Long-term Purchase Commitment [Line Items]

Long-term Purchase Commitment

Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):



	2016		2015		2014
PPA with PacifiCorp	$	12,221	$	13,990	$	13,943
Transmission services agreement with PacifiCorp	$	1,428	$	1,213	$	1,227
PPA with Happy Jack	$	3,836	$	3,155	$	3,919
PPA with Silver Sage	$	4,949	$	4,107	$	4,798
Busch Ranch Wind Farm	$	2,071	$	1,734	$	1,998
PPAs with Cargill ^(a)	$	10,995	$	16,112	$	9,286

________________


(a)	PPAs with Cargill expired on December 31, 2016.

Purchased Gas Cost Obligation

Long-term Purchase Commitment [Line Items]

Long-term Purchase Commitment

At December 31, 2016, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):



	CIG Rockies	Enable-East	NWPL-Wyoming	SSTAR-TEXOK	Other
2017	5,549,427	620,300	1,208,000	457,399	44,913
2018	—	584,000	1,208,000	—	—
2019	—	584,000	720,000	—	—
2020	—	585,600	—	—	—
2021	—	388,800	—	—	—

Guarantees (Tables)

12 Months Ended

Dec. 31, 2016

Guarantees [Abstract]

Schedule of Guarantor Obligations

We had the following guarantees in place as of (in thousands):



	Maximum Exposure at
Nature of Guarantee	December 31, 2016		Expiration
Indemnification for subsidiary reclamation/surety bonds ^(a)	$	57,105	Ongoing
	$	57,105

_______________________


(a)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited): Oil and Gas Exploration and Production Industries Disclosure (Tables)

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure

Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):



	2016		2015		2014
Acquisition of properties:
Proved	$	—	$	1,407	$	4,881
Unproved	910		669		5,056
Exploration costs	1,102		35,434		54,355
Development costs	4,657		128,998		52,262
Asset retirement obligations incurred	—		566		68
Total costs incurred	$	6,669	$	167,074	$	116,622

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.



	2016										2015										2014
	Oil			Gas			NGL				Oil			Gas			NGL				Oil			Gas			NGL
	(in Mbbls of oil and NGL, and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	3,450			73,412			1,752				4,276			65,440			1,720				3,921			63,190			—
Production ^(a)	(319		)	(9,430		)	(133		)		(371		)	(10,058		)	(102		)		(337		)	(7,156		)	(135		)
Sales	(570		)	(1,291		)	(17		)		(11		)	(828		)	—				(40		)	(61		)	—
Additions - extensions and discoveries	3			52			—				199			24,462			232				733			11,003			182
Revisions to previous estimates	(322		)	(8,173		)	110				(643		)	(5,604		)	(98		)		(1		)	(1,536		)	1,673
Balance at end of year	2,242			54,570			1,712				3,450			73,412			1,752				4,276			65,440			1,720

Proved developed reserves at end of year included above	2,242			54,570			1,712				3,436			73,390			1,752				3,780			57,427			1,530

Proved undeveloped reserves at the end of year included in above	—			—			—				14			22			—				496			8,013			191

NYMEX prices	$	42.75		$	2.48		$	—		^(b)	$	50.28		$	2.59		$	—		^(b)	$	94.99		$	4.35		$	—		^(b)

Well-head reserve prices^(c)	$	37.35		$	2.25		$	11.92			$	44.72		$	1.27		$	18.96			$	85.80		$	3.33		$	34.81

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.


(b)	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.

(c)

Schedule of Oil and Gas In Process Activities

The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2016 were:



	Proved Reserves (in Bcfe)		Gross PUD Locations		Future Development Costs (in millions)

Existing 2015:
Williston	0.1		6		$	0.5
Piceance	—		—		$	(0.1	)
Powder River	—		—		$	—
Year End Total 2015	0.1		6		$	0.4

Dropped 2016:
Williston	(0.1	)	(6	)	$	(0.5	)
Piceance	—		—		$	0.1
	(0.1	)	(6	)	$	(0.4	)

Drilled in 2016:
	—		—		$	—

Revisions:	—		—		$	—

Added in 2016:	—		—		$	—

Total Proved Undeveloped	—		—		$	—

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

Following is information concerning capitalized costs for the years ended December 31 (in thousands):



	2016			2015			2014
Unproved oil and gas properties	$	18,547		$	47,254		$	75,329
Proved oil and gas properties	1,043,558			1,008,466			807,518
Gross capitalized costs	1,062,105			1,055,720			882,847

Accumulated depreciation, depletion and amortization and valuation allowances	(1,000,091		)	(888,775		)	(612,012		)
Net capitalized costs	$	62,014		$	166,945		$	270,835

Results of Operations for Oil and Gas Producing Activities Disclosure

Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):



	2016			2015			2014
Revenue	$	34,058		$	43,283		$	55,114

Production costs	17,231			19,762			22,155
Depreciation, depletion and amortization	12,574			28,062			23,288
Impairment of long-lived assets	106,957			249,608			—
Total costs	136,762			297,432			45,443
Results of operations from producing activities before tax	(102,704		)	(254,149		)	9,671

Income tax benefit (expense)	37,916			93,743			(3,415		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	(64,788	)	$	(160,406	)	$	6,256

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):



	2016		2015		2014		Prior		Total
Leasehold acquisition cost	$	963	$	—	$	—	$	9,278	$	10,241
Exploration cost	532		441		6,443		—		7,416
Capitalized interest	50		23		335		482		890
Total	$	1,545	$	464	$	6,778	$	9,760	$	18,547

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):



	2016			2015			2014
Future cash inflows	$	246,221		$	295,173		$	675,973
Future production costs	(166,248		)	(146,552		)	(245,180		)
Future development costs, including plugging and abandonment	(18,333		)	(24,833		)	(45,123		)
Future income tax expense	—			—			(29,523		)
Future net cash flows	61,640			123,788			356,147
10% annual discount for estimated timing of cash flows	(26,574		)	(44,760		)	(173,125		)
Standardized measure of discounted future net cash flows	$	35,066		$	79,028		$	183,022

Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):



	2016			2015			2014
Standardized measure - beginning of year	$	79,028		$	183,022		$	159,425
Sales and transfers of oil and gas produced, net of production costs	(4,314		)	(29,948		)	(32,139		)
Net changes in prices and production costs	(32,698		)	(127,199		)	(28,544		)
Extensions, discoveries and improved recovery, less related costs	—			15,718			17,582
Changes in future development costs	1,825			(7,387		)	3,195
Development costs incurred during the period	—			27,211			2,079
Revisions of previous quantity estimates	(7,477		)	(6,941		)	23,722
Accretion of discount	7,903			18,870			18,437
Net change in income taxes	—			5,682			19,265
Purchases of reserves	—			—			—
Sales of reserves	(9,201		)	—			—
Standardized measure - end of year	$	35,066		$	79,028		$	183,022

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=50486907&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=68064819&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=34713648&loc=d3e63071-109448

+ Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2016 and 2015.



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2016
Revenue	$	449,959	$	325,441	$	333,786	$	463,788
Operating income(loss)	$	73,590	$	35,298	$	58,409	$	55,289
Net Income (loss)	$	40,050	$	3,283	$	17,884	$	21,414
Net income (loss) available for common stock	$	40,002	$	669	$	14,131	$	18,168

Earnings (loss) per share - Basic	$	0.78	$	0.01	$	0.27	$	0.34

Earnings (loss) per share - Diluted	$	0.77	$	0.01	$	0.26	$	0.33

Dividends paid per share	$	0.420	$	0.420	$	0.420	$	0.420

Common stock prices - High	$	61.13	$	63.53	$	64.58	$	62.83
Common stock prices - Low	$	44.65	$	56.16	$	56.86	$	54.76



	First Quarter		Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2015
Revenue	$	441,987	$	272,254		$	272,105		$	318,259
Operating income (loss)	$	70,500	$	(38,858	)	$	(2,044	)	$	197
Net Income (loss)	$	33,850	$	(41,842	)	$	(9,943	)	$	(14,176	)
Net income (loss) available for common stock	$	33,850	$	(41,842	)	$	(9,943	)	$	(14,176	)

Earnings (loss) per share - Basic	$	0.76	$	(0.94	)	$	(0.22	)	$	(0.30	)

Earnings (loss) per share - Diluted	$	0.76	$	(0.94	)	$	(0.22	)	$	(0.30	)

Dividends paid per share	$	0.405	$	0.405		$	0.405		$	0.405

Common stock prices - High	$	53.37	$	52.96		$	47.27		$	47.51
Common stock prices - Low	$	47.88	$	43.48		$	36.81		$	40.00

Business Description And Significant Accounting Policies: Segment Reporting (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue	$ 463,788	$ 333,786	$ 325,441	$ 449,959	$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 1,572,974	$ 1,304,605	$ 1,393,570
Operations and maintenance									$ 456,399	361,109	359,095
Utilities Group
Revenue										0	0
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses										0	0
Non Regulated Energy Group
Revenue										0	0
Operating Costs, Nonregulated Energy Operations										0	0
Sales Revenue, Net
Prior Period Reclassification Adjustment										1,304,605	1,393,570
Sales Revenue, Net \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										0	0
Sales Revenue, Net \| Utilities Group
Prior Period Reclassification Adjustment										(1,219,526)	(1,300,969)
Sales Revenue, Net \| Utilities Group \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										1,219,526	1,300,969
Sales Revenue, Net \| Non Regulated Energy Group
Prior Period Reclassification Adjustment										(85,079)	(92,601)
Sales Revenue, Net \| Non Regulated Energy Group \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										85,079	92,601
Operating Expense
Prior Period Reclassification Adjustment										361,109	359,095
Operating Expense \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										0	0
Operating Expense \| Utilities Group
Prior Period Reclassification Adjustment										(272,407)	(270,954)
Operating Expense \| Utilities Group \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										272,407	270,954
Operating Expense \| Non Regulated Energy Group
Prior Period Reclassification Adjustment										(88,702)	(88,141)
Operating Expense \| Non Regulated Energy Group \| Scenario, Previously Reported
Prior Period Reclassification Adjustment										$ 88,702	$ 88,141

Business Description And Significant Accounting Policies: Reclassifications (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2016
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months				$ 0.8
Net Cash Provided By Operating Activities
Prior Period Reclassification Adjustment	$ 3.7	$ 8.1
Cash and Cash Equivalents
Prior Period Reclassification Adjustment	$ 16.0	$ 12.0	$ 3.8

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (1,741)	$ (2,392)
Accounts receivable, net	147,486	263,289
Corporate, Non-Segment
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,026	2,228
Electric Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(727)	(353)
Accounts receivable, net	76,826	77,840
Electric Utilities \| Trade Accounts Receivable [Member]
Accounts Receivable [Line Items]
Prior Period Reclassification Adjustment	(6,800)
Gas Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(1,001)	(2,026)
Accounts receivable, net	62,198	174,471
Gas Utilities \| Trade Accounts Receivable [Member]
Accounts Receivable [Line Items]
Prior Period Reclassification Adjustment	6,800
Power Generation
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,187	1,420
Mining
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,760	3,352
Oil and Gas
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(13)
Accounts receivable, net	3,489	3,978
Billed Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	80,484	140,889
Billed Revenues \| Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,026	2,228
Billed Revenues \| Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	41,679	41,730
Billed Revenues \| Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	30,330	88,168
Billed Revenues \| Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,187	1,420
Billed Revenues \| Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,760	3,352
Billed Revenues \| Oil and Gas
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,502	3,991
Unbilled Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	68,743	124,792
Unbilled Revenues \| Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues \| Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	35,874	36,463
Unbilled Revenues \| Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	32,869	88,329
Unbilled Revenues \| Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues \| Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues \| Oil and Gas
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 0	$ 0

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 68,456	$ 55,726
Fuel - Electric Utilities	3,667	5,567
Natural gas in storage	35,087	25,650
Total materials, supplies and fuel	$ 107,210	$ 86,943

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 56,926	$ 43,342
Accrued property taxes	40,004	32,393
Accrued payments related to litigation expenses and settlements	0	38,750
Customer deposits and prepayments	51,628	53,496
Accrued interest and contract adjustment payments	45,503	25,762
Other (none of which is individually significant)	49,973	38,318
Total accrued liabilities	$ 244,034	$ 232,061

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 359,759	$ 353,396
Goodwill	939,695	6,363
Goodwill, Ending Balance	1,299,454	359,759	$ 353,396
Electric Utilities
Goodwill [Roll Forward]
Goodwill, Beginning Balance	248,479	248,479
Goodwill	0	0
Goodwill, Ending Balance	248,479	248,479	248,479
Electric Utilities \| Goodwill [Member]
Goodwill [Line Items]
Prior Period Reclassification Adjustment		2,000	6,300
Gas Utilities
Goodwill [Roll Forward]
Goodwill, Beginning Balance	102,515	96,152
Goodwill	939,695	6,363
Goodwill, Ending Balance	1,042,210	102,515	96,152
Gas Utilities \| Goodwill [Member]
Goodwill [Line Items]
Prior Period Reclassification Adjustment		(2,000)	(6,300)
Power Generation
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765	8,765
Goodwill	0	0
Goodwill, Ending Balance	$ 8,765	$ 8,765	$ 8,765
Aquila Transaction \| Electric Utilities
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	72.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 246,000
Aquila Transaction \| Gas Utilities
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	28.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 94,000
SourceGas Transaction \| Gas Utilities
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 940,000

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 3,380	$ 3,176	$ 3,397
Intangible assets, additions	5,522	434	0
Intangible assets, amortization expense	(510)	(230)	(221)
Intangible assets, net, ending balance	8,392	$ 3,380	$ 3,176
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	800
Future Amortization Expense, Year Two	800
Future Amortization Expense, Year Three	800
Future Amortization Expense, Year Four	800
Future Amortization Expense, Year Five	$ 800
Minimum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	2 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	40 years

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) $ in Thousands		12 Months Ended
	Apr. 29, 2016 USD ($) $ / Btu	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets		$ 296,142	$ 232,484
Regulatory liabilities		$ 206,756	153,041
Deferred energy, fuel and gas cost adjustments - current
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		1 year
Regulatory liabilities		$ 10,368	7,814
Employee benefit plans
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		12 years
Regulatory liabilities		$ 68,654	47,218
Cost of removal
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		44 years
Regulatory liabilities		$ 118,410	90,045
Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		25 years
Regulatory liabilities		$ 9,324	7,964
Deferred energy, fuel and gas cost adjustments - current
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		1 year
Regulatory assets		$ 17,491	24,751
Deferred gas cost adjustments
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		1 year
Regulatory assets		$ 15,329	15,521
Gas price derivatives
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		4 years
Regulatory assets		$ 8,843	23,583
Deferred taxes on AFUDC
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		45 years
Regulatory assets		$ 15,227	12,870
Employee benefit plans
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		12 years
Regulatory assets		$ 108,556	83,986
Environmental
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets		$ 1,108	1,180
Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		44 years
Regulatory assets		$ 505	457
Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		22 years
Regulatory assets		$ 20,188	3,133
Renewable energy standard adjustment
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		5 years
Regulatory assets		$ 1,605	5,068
Deferred taxes on flow through accounting
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		35 years
Regulatory assets		$ 37,498	29,722
Decommissioning costs
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		10 years
Regulatory assets		$ 16,859	18,310
Gas supply contract termination
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	5 years	5 years
Regulatory assets	$ 30,000	$ 26,666	0
Other regulatory assets
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		15 years
Regulatory assets		$ 26,267	$ 13,903
Minimum
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price \| $ / Btu	6
Minimum \| Gas supply contract termination
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price \| $ / Btu	6
Maximum
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price \| $ / Btu	8
Maximum \| Gas supply contract termination
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price \| $ / Btu	8

Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income (loss) available for common stock	$ 18,168	$ 14,131	$ 669	$ 40,002	$ (14,176)	$ (9,943)	$ (41,842)	$ 33,850	$ 72,970	$ (32,111)	$ 130,889
Weighted average shares - Basic (in shares)									51,922,000	45,288,000	44,394,000
Dilutive effect of:
Equity Units (in shares)									1,222,000	0	0
Equity compensation (in shares)									127,000	0	204,000
Weighted average shares - diluted (in shares)									53,271,000	45,288,000	44,598,000
Earnings (loss) per share, Diluted (usd per share)	$ 0.33	$ 0.26	$ 0.01	$ 0.77	$ (0.30)	$ (0.22)	$ (0.94)	$ 0.76	$ 1.37	$ (0.71)	$ 2.93
Equity compensation shares excluded (in shares)									83,000

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	3	6,552	81
Equity Compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	3	112	81
Equity Unit Purchase Agreements
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	0	6,440	0

Business Description And Significant Accounting Policies: Balance Sheet Classification of Debt Issuance Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Other Assets, Non-Current
Prior Period Reclassification Adjustment	$ (13)
Long-term Debt
Prior Period Reclassification Adjustment	$ (13)

Acquisition (Details) $ / shares in Units, $ in Thousands					3 Months Ended								12 Months Ended
Acquisition (Details) $ / shares in Units, $ in Thousands	Apr. 29, 2016 USD ($) $ / Btu	Feb. 12, 2016 USD ($) customer utility mi	Jan. 13, 2016 USD ($)	Nov. 23, 2015 USD ($) shares	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) $ / shares shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($)
Acquisition Narrative [Abstract]
Ownership of subsidiary (percent)													99.50%
Cash consideration paid													$ 1,135,000
Proceeds from issuance of shares				$ 536,000
Long-term debt - issuance			$ 546,000										1,767,608	$ 300,000	$ 160,000
Revenue					$ 463,788	$ 333,786	$ 325,441	$ 449,959	$ 318,259	$ 272,105	$ 272,254	$ 441,987	1,572,974	1,304,605	1,393,570
Net income (loss) available for common stock					18,168	$ 14,131	$ 669	$ 40,002	(14,176)	$ (9,943)	$ (41,842)	$ 33,850	72,970	(32,111)	130,889
Cash consideration paid		$ (1,124,238)											1,124,238	21,970	0
Decrease of goodwill		6,700
Acquisition Recap [Abstract]
Consideration Paid, net of working capital adjustment received		$ (1,124,238)											1,124,238	21,970	0
Goodwill					1,299,454				359,759				1,299,454	359,759	353,396
Settlement of Gas Supply Contract [Abstract]
Settlement of gas supply contract	$ 40,000
Contract committed to distribution customers, percent	75.00%
Contract not subject to regulatory recovery, percent	25.00%
Regulatory assets					$ 296,142				232,484				$ 296,142	232,484
Pro Forma Results
Estimated combined federal and state income tax rate (percent)													37.00%
Noncontrolling Interest [Abstract]
Sellers retention (percent)					0.50%								0.50%
Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Regulatory assets	$ 30,000				$ 26,666				0				$ 26,666	0
Recovery period	5 years												5 years
Minimum
Settlement of Gas Supply Contract [Abstract]
Contract prices \| $ / Btu	6
Minimum \| Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Contract prices \| $ / Btu	6
Maximum
Settlement of Gas Supply Contract [Abstract]
Contract prices \| $ / Btu	8
Maximum \| Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Contract prices \| $ / Btu	8
Corporate, Non-Segment
Acquisition Narrative [Abstract]
Pre-tax, incremental acquisition costs													$ 45,000	10,000
Revenue													347,500	227,708	222,460
Net income (loss) available for common stock													$ 143,049	$ 57,150	61,538
Remarketable Junior Subordinated Notes Due 2028
Acquisition Narrative [Abstract]
Issuance of equity units \| shares				5,980,000
Common Stock
Acquisition Narrative [Abstract]
Issuance of common stock, shares \| shares				6,325,000									1,968,738	6,325,000
Source Gas
Acquisition Narrative [Abstract]
Number of natural gas utilities acquired \| utility		4
Number of customers served with acquisition \| customer		429,000
Length of natural gas pipeline (miles) \| mi		512
Revenue													$ 348,000
Net income (loss) available for common stock													15,000
Expected tax deductible goodwill					252,000								252,000
Acquisition Recap [Abstract]
Purchase Price		$ 1,894,882
Less: Long-term debt assumed		760,000
Less: Working capital adjustment received		10,644
Current Assets		112,983
Property, plant & equipment, net		1,058,093
Deferred charges and other assets, excluding goodwill		133,299
Current liabilities		172,454
Long-term debt		758,874
Deferred credits and other liabilities		188,504
Total consideration paid, net of working-capital adjustment received		$ 1,124,238
Pro Forma Results
Revenue													1,651,936	$ 1,763,901
Net income (loss) available for common stock													$ 112,878	$ (13,369)
Earnings (loss) per share, Basic (usd per share) \| $ / shares													$ 2.17	$ (0.26)
Earnings (loss) per share, Diluted (usd per share) \| $ / shares													$ 2.12	$ (0.26)
Source Gas \| Black Hills Energy, Arkansas
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Base Rate Moratorium Imposed by ASPC		12 months
Annual Amount of Customer Credit													$ 250
Source Gas \| Black Hills Energy, Arkansas \| Maximum
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit		5 years
Source Gas \| Rocky Mountain Natural Gas
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by CPUC		2 years
Source Gas \| Black Hills Gas Distribution, Colorado
Public Utilities, Rate Matters, Approved [Abstract]
Annual Amount of Customer Credit													200
Duration of Base Rate Moratorium imposed by CPUC		3 years
Source Gas \| Black Hills Gas Distribution, Colorado \| Maximum
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit		5 years
Source Gas \| Black Hills Gas Distribution - Nebraska
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by NPSC		3 years
Continuation Period of Choice Gas Program		3 years
Source Gas \| Black Hills Gas Distribution - Wyoming
Public Utilities, Rate Matters, Approved [Abstract]
Continuation Period of Choice Gas Program		3 years
Gas Utilities
Acquisition Narrative [Abstract]
Revenue													838,343	$ 551,300	657,523
Net income (loss) available for common stock													59,624	39,306	44,151
Acquisition Recap [Abstract]
Goodwill					1,042,210				$ 102,515				1,042,210	$ 102,515	$ 96,152
Gas Utilities \| SourceGas Transaction
Acquisition Recap [Abstract]
Goodwill		$ 939,695			$ 940,000								$ 940,000

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,412,223	$ 4,976,778
Less: accumulated depreciation, depletion and amortization	1,943,234	1,717,684
Total property, plant and equipment, net	4,468,989	3,259,094
Oil and Gas Property, Full Cost Method, Net	43,000
Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	17,420	15,753
Total property, plant and equipment, net	23,535	20,523
Property, plant and equipment	5,446	376
Construction in progress, gross	11,974	15,377
Intercompany Eliminations
Property, Plant and Equipment [Line Items]
Less: accumulated depreciation, depletion and amortization	$ (6,115)	$ (4,770)
Weighted Average \| Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	8 years	10 years
Minimum \| Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years	5 years
Maximum \| Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years	30 years
Electric Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 2,801,549	$ 2,542,686
Construction work in progress	74,045	96,501
Property, plant and equipment, gross	2,875,594	2,639,187
Less: accumulated depreciation, depletion and amortization	578,162	526,954
Total property, plant and equipment, net	$ 2,297,432	2,112,233
Depreciation, depletion and amortization, remaining amortization period	14 years
Electric Utilities \| Property, Plant and Equipment Net Of Accumulated Depreciation
Property, Plant and Equipment [Line Items]
Prior Period Reclassification Adjustment		(117,000)
Electric Utilities \| Production, Electric
Property, Plant and Equipment [Line Items]
Production	$ 1,303,101	$ 1,136,847
Electric Utilities \| Production, Electric \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	41 years	43 years
Electric Utilities \| Production, Electric \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years
Electric Utilities \| Production, Electric \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	63 years
Electric Utilities \| Electric transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 354,801	$ 280,257
Electric Utilities \| Electric transmission \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	52 years	50 years
Electric Utilities \| Electric transmission \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years
Electric Utilities \| Electric transmission \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	70 years
Electric Utilities \| Electric distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 712,575	$ 699,775
Electric Utilities \| Electric distribution \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years	47 years
Electric Utilities \| Electric distribution \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years
Electric Utilities \| Electric distribution \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	75 years
Electric Utilities \| Plant acquisition adjustment
Property, Plant and Equipment [Line Items]
Plant acquisition adjustment	$ 4,870	$ 4,870
Electric Utilities \| Plant acquisition adjustment \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years	32 years
Electric Utilities \| Plant acquisition adjustment \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities \| Plant acquisition adjustment \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities \| General
Property, Plant and Equipment [Line Items]
General	$ 164,761	$ 159,496
Electric Utilities \| General \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	25 years	24 years
Electric Utilities \| General \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years
Electric Utilities \| General \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	65 years
Electric Utilities \| Capital lease - plant in service
Property, Plant and Equipment [Line Items]
Capital lease - plant in service	$ 261,441	$ 261,441
Electric Utilities \| Capital lease - plant in service \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years	20 years
Electric Utilities \| Capital lease - plant in service \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Electric Utilities \| Capital lease - plant in service \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Gas Utilities
Property, Plant and Equipment [Line Items]
Production	$ 10,821	$ 13
Total plant in service before construction work in progress	2,070,578	860,026
Construction work in progress	28,446	11,854
Property, plant and equipment, gross	2,099,024	871,880
Less: accumulated depreciation, depletion and amortization	194,585	120,458
Total property, plant and equipment, net	$ 1,904,439	$ 751,422
Gas Utilities \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	35 years	30 years
Gas Utilities \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	17 years
Gas Utilities \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	71 years
Gas Utilities \| Property, Plant and Equipment Net Of Accumulated Depreciation
Property, Plant and Equipment [Line Items]
Prior Period Reclassification Adjustment		$ 117,000
Gas Utilities \| General
Property, Plant and Equipment [Line Items]
General	$ 339,382	$ 122,109
Gas Utilities \| General \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	19 years	22 years
Gas Utilities \| General \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years
Gas Utilities \| General \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	44 years
Gas Utilities \| Gas transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 338,729	$ 45,104
Gas Utilities \| Gas transmission \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years	60 years
Gas Utilities \| Gas transmission \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	22 years
Gas Utilities \| Gas transmission \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	70 years
Gas Utilities \| Gas distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 1,303,366	$ 692,800
Gas Utilities \| Gas distribution \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	42 years	45 years
Gas Utilities \| Gas distribution \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years
Gas Utilities \| Gas distribution \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	47 years
Gas Utilities \| Cushion Gas - Depreciable
Property, Plant and Equipment [Line Items]
Production	$ 3,539	$ 0
Gas Utilities \| Cushion Gas - Depreciable \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years	0 years
Gas Utilities \| Cushion Gas - Depreciable \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years
Gas Utilities \| Cushion Gas - Depreciable \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years
Gas Utilities \| Cushion Gas - Not Depreciated
Property, Plant and Equipment [Line Items]
Production	$ 47,055	$ 0
Gas Utilities \| Cushion Gas - Not Depreciated \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years	0 years
Gas Utilities \| Cushion Gas - Not Depreciated \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years
Gas Utilities \| Cushion Gas - Not Depreciated \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years
Gas Utilities \| Production, Gas
Property, Plant and Equipment [Line Items]
Production	$ 27,686	$ 0
Gas Utilities \| Production, Gas \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	31 years	0 years
Gas Utilities \| Production, Gas \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years
Gas Utilities \| Production, Gas \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years
Power Generation
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 162,728	$ 158,903
Less: accumulated depreciation, depletion and amortization	55,157	51,471
Total property, plant and equipment, net	107,571	107,432
Property, plant and equipment	161,430	156,721
Construction in progress, gross	$ 1,298	$ 2,182
Power Generation \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years	33 years
Power Generation \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	2 years
Power Generation \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years	40 years
Mining
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 156,351	$ 158,279
Less: accumulated depreciation, depletion and amortization	105,219	97,663
Total property, plant and equipment, net	51,132	60,616
Property, plant and equipment	151,709	154,630
Construction in progress, gross	$ 4,642	$ 3,649
Mining \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	13 years	13 years
Mining \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	2 years
Mining \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	59 years	59 years
Oil and Gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 1,101,106	$ 1,132,776
Less: accumulated depreciation, depletion and amortization	1,016,226	925,908
Total property, plant and equipment, net	84,880	206,868
Property, plant and equipment	1,101,106	1,132,776
Construction in progress, gross	$ 0	$ 0
Oil and Gas \| Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	25 years	24 years
Oil and Gas \| Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	3 years
Oil and Gas \| Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	25 years	25 years

Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Electric Utilities \| Wyodak Plant
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	20.00%
Plant in Service	$ 113,611
Construction Work in Progress	256
Accumulated Depreciation	$ 55,878
Electric Utilities \| Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	35.00%
Plant in Service	$ 19,978
Construction Work in Progress	13
Accumulated Depreciation	$ 5,793
Electric Utilities \| Wygen I I I Generating Facility
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	52.00%
Plant in Service	$ 138,261
Construction Work in Progress	1,806
Accumulated Depreciation	$ 17,635
Electric Utilities \| Busch Ranch Wind Farm
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	50.00%
Plant in Service	$ 18,899
Construction Work in Progress	0
Accumulated Depreciation	$ 3,102
Power Generation \| Wygen I Generating Facility
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	76.50%
Plant in Service	$ 109,412
Construction Work in Progress	957
Accumulated Depreciation	$ 37,156

Business Segments Information: Segment Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item
Total Assets	$ 4,626,643	$ 6,515,444
Corporate, Non-Segment
Segment Reporting, Asset Reconciling Item
Total Assets	576,357	110,691
Electric Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	2,704,330	2,859,559
Electric Utilities \| Assets
Segment Reporting, Asset Reconciling Item
Prior Period Reclassification Adjustment	(135,000)
Gas Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	999,778	3,307,967
Gas Utilities \| Assets
Segment Reporting, Asset Reconciling Item
Prior Period Reclassification Adjustment	135,000
Power Generation
Segment Reporting, Asset Reconciling Item
Total Assets	60,864	73,445
Mining
Segment Reporting, Asset Reconciling Item
Total Assets	76,358	67,347
Oil and Gas
Segment Reporting, Asset Reconciling Item
Total Assets	$ 208,956	$ 96,435

Business Segments Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 12, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		$ 467,119	$ 458,821
Acquisition of net assets, net of long-term debt assumed	$ 1,124,238	(1,124,238)	(21,970)	$ 0
Property, Plant and Equipment Including New Asset Acquisitions, Gross Period Increase (Decrease)		1,591,357	480,791
Gas Utilities
Segment Reporting Information [Line Items]
Acquisition of net assets, net of long-term debt assumed		1,124,238	21,970
Source Gas
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	$ 1,124,000
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		17,353	9,864
Electric Utilities
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		258,739	171,897
Electric Utilities \| Capital Expenditures
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment			(30,000)
Gas Utilities
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		173,930	99,674
Gas Utilities \| Capital Expenditures
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment			30,000
Power Generation
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		4,719	2,694
Mining
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		5,709	5,767
Oil and Gas
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		$ 6,669	$ 168,925

Business Segments Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Segment Reporting Information [Line Items]
Property, plant and equipment	$ 4,976,778	$ 6,412,223
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Property, plant and equipment	15,753	17,420
Electric Utilities
Segment Reporting Information [Line Items]
Property, plant and equipment	2,639,187	2,875,594
Electric Utilities \| Property, Plant and Equipment
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment	(130,000)
Gas Utilities
Segment Reporting Information [Line Items]
Property, plant and equipment	871,880	2,099,024
Gas Utilities \| Property, Plant and Equipment
Segment Reporting Information [Line Items]
Prior Period Reclassification Adjustment	130,000
Power Generation
Segment Reporting Information [Line Items]
Property, plant and equipment	158,903	162,728
Mining
Segment Reporting Information [Line Items]
Property, plant and equipment	158,279	156,351
Oil and Gas
Segment Reporting Information [Line Items]
Property, plant and equipment	$ 1,132,776	$ 1,101,106

Business Segments Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information
Revenue	$ 463,788	$ 333,786	$ 325,441	$ 449,959	$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 1,572,974	$ 1,304,605	$ 1,393,570
Fuel, purchased power and cost of natural gas sold									499,132	456,887	581,782
Operations and maintenance									555,256	412,945	403,175
Depreciation, depletion and amortization									189,043	155,370	144,745
Impairment of long-lived assets									106,957	249,608	0
Operating income	55,289	58,409	35,298	73,590	197	(2,044)	(38,858)	70,500	222,586	29,795	263,868
Interest expense									(135,412)	(83,719)	(70,960)
Interest income									1,429	1,621	1,925
Other income (expense), net									4,503	2,437	2,681
Impairment of equity investments									0	(4,405)	0
Income tax benefit (expense)									(10,475)	22,160	(66,625)
Net income (loss)									82,631	(32,111)	130,889
Net income attributable to noncontrolling interest									(9,661)	0	0
Net income (loss) available for common stock	$ 18,168	$ 14,131	$ 669	$ 40,002	$ (14,176)	$ (9,943)	$ (41,842)	$ 33,850	72,970	(32,111)	130,889
Electric Utilities
Segment Reporting Information
Revenue									664,330	668,226	643,446
Fuel, purchased power and cost of natural gas sold									261,349	269,409	291,644
Operations and maintenance									158,134	160,924	156,252
Depreciation, depletion and amortization									84,645	80,929	77,011
Impairment of long-lived assets									0	0
Operating income									173,153	168,581	132,649
Interest expense									(56,237)	(55,159)	(51,640)
Interest income									5,946	4,114	4,590
Other income (expense), net									3,193	1,216	1,074
Impairment of equity investments										0
Income tax benefit (expense)									(40,228)	(41,173)	(29,403)
Net income (loss)									85,827	77,579	57,270
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									85,827	77,579	57,270
Gas Utilities
Segment Reporting Information
Revenue									838,343	551,300	657,523
Fuel, purchased power and cost of natural gas sold									352,165	299,645	403,781
Operations and maintenance									245,826	140,723	142,024
Depreciation, depletion and amortization									78,335	32,326	28,912
Impairment of long-lived assets									0	0
Operating income									162,017	78,606	82,806
Interest expense									(76,586)	(17,912)	(17,487)
Interest income									1,573	601	466
Other income (expense), net									184	315	124
Impairment of equity investments										0
Income tax benefit (expense)									(27,462)	(22,304)	(21,758)
Net income (loss)									59,726	39,306	44,151
Net income attributable to noncontrolling interest									(102)	0	0
Net income (loss) available for common stock									59,624	39,306	44,151
Power Generation
Segment Reporting Information
Revenue									7,176	7,483	6,401
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									32,636	32,140	33,126
Depreciation, depletion and amortization									4,104	4,329	4,540
Impairment of long-lived assets									0	0
Operating income									54,391	54,321	49,892
Interest expense									(3,758)	(4,218)	(4,351)
Interest income									1,983	1,015	682
Other income (expense), net									2	71	(6)
Impairment of equity investments										0
Income tax benefit (expense)									(17,129)	(18,539)	(17,701)
Net income (loss)									35,489	32,650	28,516
Net income attributable to noncontrolling interest									(9,559)	0	0
Net income (loss) available for common stock									25,930	32,650	28,516
Mining
Segment Reporting Information
Revenue									29,067	34,313	31,086
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									39,576	41,630	41,172
Depreciation, depletion and amortization									9,346	9,806	10,276
Impairment of long-lived assets									0	0
Operating income									11,358	13,630	11,910
Interest expense									(401)	(433)	(493)
Interest income									24	34	59
Other income (expense), net									2,209	2,247	2,275
Impairment of equity investments										0
Income tax benefit (expense)									(3,137)	(3,608)	(3,299)
Net income (loss)									10,053	11,870	10,452
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									10,053	11,870	10,452
Oil and Gas
Segment Reporting Information
Revenue									34,058	43,283	55,114
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									32,158	41,593	42,659
Depreciation, depletion and amortization									13,902	29,287	24,246
Impairment of long-lived assets									106,957	249,608
Operating income									(118,959)	(277,205)	(11,791)
Interest expense									(4,864)	(2,726)	(2,603)
Interest income									0	217	918
Other income (expense), net									110	(337)	183
Impairment of equity investments										(4,405)
Income tax benefit (expense)									52,659	104,498	4,768
Net income (loss)									(71,054)	(179,958)	(8,525)
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									(71,054)	(179,958)	(8,525)
Intercompany Eliminations
Segment Reporting Information
Revenue									(475,619)	(353,385)	(349,999)
Fuel, purchased power and cost of natural gas sold									(114,838)	(112,289)	(113,759)
Operations and maintenance									(326,847)	(229,786)	(225,473)
Depreciation, depletion and amortization									(23,827)	(10,580)	(7,930)
Impairment of long-lived assets									0	0
Operating income									(10,107)	(730)	(2,837)
Interest expense									115,469	54,568	55,913
Interest income									(105,244)	(52,942)	(53,759)
Other income (expense), net									(181,034)	(71,964)	(62,574)
Impairment of equity investments										0
Income tax benefit (expense)									457	360	744
Net income (loss)									(180,459)	(70,708)	(62,513)
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									(180,459)	(70,708)	(62,513)
Intercompany Eliminations \| Electric Utilities
Segment Reporting Information
Revenue									12,951	11,617	14,110
Intercompany Eliminations \| Gas Utilities
Segment Reporting Information
Revenue									0	0	0
Intercompany Eliminations \| Power Generation
Segment Reporting Information
Revenue									83,955	83,307	81,157
Intercompany Eliminations \| Mining
Segment Reporting Information
Revenue									31,213	30,753	32,272
Intercompany Eliminations \| Oil and Gas
Segment Reporting Information
Revenue									0	0	0
Operating Segments \| Electric Utilities
Segment Reporting Information
Revenue									677,281	679,843	657,556
Operating Segments \| Gas Utilities
Segment Reporting Information
Revenue									838,343	551,300	657,523
Operating Segments \| Power Generation
Segment Reporting Information
Revenue									91,131	90,790	87,558
Operating Segments \| Mining
Segment Reporting Information
Revenue									60,280	65,066	63,358
Operating Segments \| Oil and Gas
Segment Reporting Information
Revenue									34,058	43,283	55,114
Corporate, Non-Segment
Segment Reporting Information
Revenue									347,500	227,708	222,460
Fuel, purchased power and cost of natural gas sold									456	122	116
Operations and maintenance									373,773	225,721	213,415
Depreciation, depletion and amortization									22,538	9,273	7,690
Impairment of long-lived assets									0	0
Operating income									(49,267)	(7,408)	1,239
Interest expense									(109,035)	(57,839)	(50,299)
Interest income									97,147	48,582	48,969
Other income (expense), net									179,839	70,889	61,605
Impairment of equity investments										0
Income tax benefit (expense)									24,365	2,926	24
Net income (loss)									143,049	57,150	61,538
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									143,049	57,150	61,538
Consolidation, Eliminations
Segment Reporting Information
Revenue									$ 0	$ 0	$ 0

Long-Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Aug. 19, 2016	Jun. 07, 2016	Jan. 13, 2016	Dec. 31, 2015	Nov. 23, 2015
Debt Instrument [Line Items]
Total long-term debt	$ 3,238,754				$ 1,866,866
Less current maturities	(5,743)				0
Less deferred financing costs	(21,822)				(13,184)
Long-term debt, net of current maturities	3,211,189				1,853,682
Revolving Credit Facility
Debt Instrument [Line Items]
Less deferred financing costs	(2,300)				(1,700)
Electric Utilities
Debt Instrument [Line Items]
Long-term debt	544,855				544,855
Less unamortized debt discount	(94)				(99)
Total long-term debt	$ 544,761				544,756
Electric Utilities \| First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Interest rate (percent)	7.23%
Long-term debt	$ 75,000				75,000
Electric Utilities \| First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Interest rate (percent)	6.13%
Long-term debt	$ 180,000				180,000
Electric Utilities \| First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Interest rate (percent)	6.67%
Long-term debt	$ 110,000				110,000
Electric Utilities \| Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	Sep. 01, 2021
Long-term Debt, Variable Interest Rate	0.72%
Long-term debt	$ 7,000				7,000
Electric Utilities \| Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	Mar. 01, 2027
Long-term Debt, Variable Interest Rate	0.72%
Long-term debt	$ 10,000				10,000
Electric Utilities \| Series 94 A Debt, Due 2024
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	0.88%
Long-term debt	$ 2,855				2,855
Black Hills Corporation
Debt Instrument [Line Items]
Long-term debt	2,698,406				1,324,000
Less unamortized debt discount	(4,413)				(1,890)
Total long-term debt	$ 2,693,993				1,322,110
Black Hills Corporation \| Senior Unsecured Notes Due 2023
Debt Instrument [Line Items]
Interest rate (percent)	4.25%
Long-term debt	$ 525,000				525,000
Black Hills Corporation \| Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Interest rate (percent)	5.875%
Long-term debt	$ 200,000				200,000
Black Hills Corporation \| Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Interest rate (percent)	3.50%					3.50%
Long-term debt	$ 299,000				299,000	$ 299,000
Black Hills Corporation \| London Interbank Offered Rate (LIBOR) \| Corporate Term Loan Due April 2017
Debt Instrument [Line Items]
Long-term debt	$ 0				300,000
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Interest rate (percent)	2.50%			2.50%
Long-term debt	$ 250,000			$ 250,000	0
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Interest rate (percent)	3.95%			3.95%
Long-term debt	$ 300,000			$ 300,000	0
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Interest rate (percent)	3.15%	3.15%
Long-term debt	$ 400,000	$ 400,000			0
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Interest rate (percent)	4.20%	4.20%
Long-term debt	$ 300,000	$ 300,000			0
Black Hills Corporation \| Corporate, Non-Segment \| Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Interest rate (percent)	2.32%		2.32%
Long-term debt	$ 24,406		$ 29,000		0
Black Hills Corporation \| Corporate, Non-Segment \| London Interbank Offered Rate (LIBOR) \| Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	1.7447%
Long-term debt	$ 400,000				0
South Dakota Electric \| Electric Utilities \| First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Interest rate (percent)	4.43%
Long-term debt	$ 85,000				85,000
Wyoming Electric \| Electric Utilities \| First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Interest rate (percent)	4.53%
Long-term debt	$ 75,000				$ 75,000

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
2017	$ 5,743	$ 0
2018	5,743
2019	655,742
2020	205,742
2021	8,436
Thereafter	$ 2,361,855

Long-Term Debt: Assumption Of Long-Term Debt (Details) - Source Gas - USD ($) $ in Thousands	Aug. 19, 2016	Feb. 12, 2016
Debt Instrument [Line Items]
Assumed long-term debt		$ 760,000
Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Assumed long-term debt		$ 325,000
Interest rate (percent)	5.90%	5.90%
Senior Secured Notes Due 2019
Debt Instrument [Line Items]
Assumed long-term debt		$ 95,000
Interest rate (percent)	3.98%	3.98%
Corporate Term Loan Due June 2017
Debt Instrument [Line Items]
Assumed long-term debt		$ 340,000
Corporate Term Loan Due June 2017 \| London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Interest rate (percent)		0.875%

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands				6 Months Ended	12 Months Ended
	Aug. 19, 2016	Aug. 09, 2016	Jan. 13, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 07, 2016	Feb. 12, 2016
Debt Instrument [Line Items]
Interest rate swap settlement					$ 28,820	$ 0	$ 0
Net proceeds from the offering			$ 546,000		1,767,608	300,000	$ 160,000
Interest Rate Swap
Debt Instrument [Line Items]
Interest rate swap settlement	$ 29,000				(29,000)
Notional amount	$ 400,000				400,000
Senior Unsecured Notes Due 2017 \| Source Gas
Debt Instrument [Line Items]
Interest rate (percent)	5.90%								5.90%
Repayment of debt	$ 325,000
Senior Secured Notes Due 2019 \| Source Gas
Debt Instrument [Line Items]
Interest rate (percent)	3.98%								3.98%
Repayment of debt	$ 95,000
Corporate Term Loan Due June 2017 \| Source Gas
Debt Instrument [Line Items]
Repayment of debt	100,000	$ 240,000
Corporate, Non-Segment \| Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Proceeds from senior unsecured notes	500,000
Debt term		3 years
Repayment of debt	100,000
Corporate, Non-Segment \| Corporate Term Loan Due April 2017
Debt Instrument [Line Items]
Repayment of debt		$ 260,000
Black Hills Corporation
Debt Instrument [Line Items]
Proceeds from senior unsecured notes	700,000		550,000
Long-term debt					2,698,406	1,324,000
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Long-term debt	$ 400,000				$ 400,000	0
Interest rate (percent)	3.15%				3.15%
Debt term	10 years				10 years
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Long-term debt	$ 300,000				$ 300,000	0
Interest rate (percent)	4.20%				4.20%
Debt term	30 years
Black Hills Corporation \| Corporate, Non-Segment \| Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Long-term debt					$ 24,406	0		$ 29,000
Interest rate (percent)					2.32%			2.32%
Frequency of periodic payment					quarterly
Periodic payment				$ 1,600
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Long-term debt			$ 300,000		$ 300,000	0
Interest rate (percent)			3.95%		3.95%
Debt term			10 years
Black Hills Corporation \| Corporate, Non-Segment \| Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Long-term debt			$ 250,000		$ 250,000	$ 0
Interest rate (percent)			2.50%		2.50%
Debt term			3 years

Long-Term Debt: Deferred Financing Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$ 21,822
Amortization expense for deferred financing costs	3,861	$ 5,617	$ 1,641
Senior Unsecured Notes Due 2023
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,921
Amortization expense for deferred financing costs	494	494	653
Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	763
Amortization expense for deferred financing costs	643	0	0
Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	592
Amortization expense for deferred financing costs	167	167	167
Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,318
Amortization expense for deferred financing costs	262	0	0
Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	3,281
Amortization expense for deferred financing costs	121	0	0
Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	3,193
Amortization expense for deferred financing costs	37	0	0
Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	287
Amortization expense for deferred financing costs	144	0	0
Bridge Term Loan
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	0
Amortization expense for deferred financing costs	843	4,213	0
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,449
Amortization expense for deferred financing costs	122	10	0
First Mortgage Bonds Due 2044 \| South Dakota Electric
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	663
Amortization expense for deferred financing costs	24	24	6
First Mortgage Bonds Due 2044 \| Wyoming Electric
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	613
Amortization expense for deferred financing costs	23	22	6
First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	518
Amortization expense for deferred financing costs	33	33	33
First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,734
Amortization expense for deferred financing costs	76	76	76
First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	643
Amortization expense for deferred financing costs	31	31	31
Deferred Financing Costs, Other
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	506
Amortization expense for deferred financing costs	304	43	53
Revolving Credit Facility
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,341
Amortization expense for deferred financing costs	$ 537	$ 504	$ 616

Long-Term Debt: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2016 USD ($)
Utilities Group
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Notes Payable (Details)		12 Months Ended
Notes Payable (Details)	Aug. 09, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jun. 30, 2016 USD ($)
Revolving Credit Facility [Line Items]
Revolving Credit Facility		$ 96,600,000	$ 76,800,000
Commercial Paper [Abstract]
Commercial Paper		750,000,000
Deferred Finance Costs [Abstract]
Deferred Financing Costs Remaining on Balance Sheet		21,822,000
Amortization expense for deferred financing costs		3,861,000	5,617,000	$ 1,641,000
Revolving Credit Facility
Revolving Credit Facility [Line Items]
Revolving Credit Facility		96,600,000	76,800,000
Current borrowing capacity	$ 750,000,000				$ 500,000,000
Number Of One-Year Extension Options	2
Debt term	1 year
Maximum Borrowing Capacity		$ 1,000,000,000
Commitment Fee Percentage		0.20%
Letters of Credit Outstanding		$ 36,000,000	33,000,000
Commercial Paper [Abstract]
Commercial paper, term	1 year
Deferred Finance Costs [Abstract]
Deferred financing costs		5,400,000
Deferred Financing Costs Remaining on Balance Sheet		2,341,000
Amortization expense for deferred financing costs		$ 537,000	$ 504,000	$ 616,000
Debt Covenants Disclosure [Abstract]
Consolidated Indebtedness to Capitalization Ratio, Requirement (percent)		0.70
Consolidated Indebtedness to Capitalization Ratio, Actual (percent)		62.00%
Revolving Credit Facility \| Base Rate Borrowings
Revolving Credit Facility [Line Items]
Interest Rate at Period End		0.25%
Revolving Credit Facility \| Eurodollar Borrowings
Revolving Credit Facility [Line Items]
Interest Rate at Period End		1.25%
Revolving Credit Facility \| Letters of Credit
Revolving Credit Facility [Line Items]
Interest Rate at Period End		1.25%
Commercial Paper
Revolving Credit Facility [Line Items]
Debt term		397 days
Commercial Paper [Abstract]
Commercial Paper, Unused Borrowing Capacity, Amount		$ 750,000,000
Commercial paper, term		397 days
Maximum
Debt Covenants Disclosure [Abstract]
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year		0.65
Consolidated Indebtedness to Capitalization Ratio, Requirement (percent)		0.70

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 44,735	$ 47,386
Liabilities Incurred	3	828
Liabilities Settled	(2,154)	(4,693)
Accretion	3,186	2,560
Liabilities Acquired	22,412	0
Revisions to Prior Estimates	1,457	(1,346)
Ending Balance	69,639	44,735
Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	4,462	7,012
Liabilities Incurred	0	0
Liabilities Settled	0	(2,733)
Accretion	191	183
Liabilities Acquired	0	0
Revisions to Prior Estimates	8	0
Ending Balance	4,661	4,462
Gas Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	136	291
Liabilities Incurred	0	0
Liabilities Settled	0	(168)
Accretion	791	13
Liabilities Acquired	22,412	0
Revisions to Prior Estimates	6,436	0
Ending Balance	29,775	136
Retirement of gas pipelines liability	22,000
Mining
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	18,633	19,138
Liabilities Incurred	0	0
Liabilities Settled	(105)	0
Accretion	822	993
Liabilities Acquired	0	0
Revisions to Prior Estimates	(6,910)	(1,498)
Ending Balance	$ 12,440	18,633
Estimated change in equipment costs (percent)	33.00%
Oil and Gas
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 21,504	20,945
Liabilities Incurred	3	828
Liabilities Settled	(2,049)	(1,792)
Accretion	1,382	1,371
Liabilities Acquired	0	0
Revisions to Prior Estimates	1,923	152
Ending Balance	$ 22,763	$ 21,504

Risk Management Activities (Details) $ in Thousands			1 Months Ended	12 Months Ended
Risk Management Activities (Details) $ in Thousands	Aug. 19, 2016 USD ($)	Aug. 09, 2016	Jan. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) MMBTU bbl	Dec. 31, 2015 USD ($) MMBTU bbl	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Interest rate swap settlement				$ 28,820	$ 0	$ 0
Effective portion of the loss reclassified from AOCI				28,000
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)				1,000
Derivative assets, non-current				222	3,441
Derivative liabilities, current				2,459	2,835
Derivative liabilities, non-current				274	156
Oil and Gas
Derivative [Line Items]
Loss to be reclassified within twelve months				(900)
Revolving Credit Facility
Derivative [Line Items]
Debt term		1 year
Black Hills Corporation
Derivative [Line Items]
Long-term debt				2,698,406	1,324,000
Corporate, Non-Segment \| Black Hills Corporation \| Senior Unsecured Notes Due 2027
Derivative [Line Items]
Long-term debt	$ 400,000			$ 400,000	0
Debt term	10 years			10 years
Cash Flow Hedging
Derivative [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)				$ (953)	0	0
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)				7,106	$ 10,813	(5,664)
Interest Rate Swap
Derivative [Line Items]
Notional amount	$ 400,000			400,000
Interest rate swap settlement	$ 29,000			(29,000)
Interest Rate Swap \| Designated as Hedging Instrument
Derivative [Line Items]
Cash flow hedge loss to be reclassified during next 12 months, Net				$ 2,900
Interest Rate Swap \| Interest Rate Swap One \| Designated as Hedging Instrument
Derivative [Line Items]
Maximum Term					16 months
Notional amount					$ 250,000
Weighted average fixed interest rate					2.29%
Derivative assets, non-current					$ 3,441
Derivative liabilities, current					0
Derivative liabilities, non-current					$ 0
Interest Rate Swap \| Revolving Credit Facility \| Designated as Hedging Instrument
Derivative [Line Items]
Maximum Term				1 month	13 months
Notional amount				$ 50,000	$ 75,000
Weighted average fixed interest rate				4.94%	4.97%
Derivative assets, non-current				$ 0	$ 0
Derivative liabilities, current				90	2,835
Derivative liabilities, non-current				0	156
Derivative Expired During the Period				25,000
Interest Rate Swap \| Cash Flow Hedging
Derivative [Line Items]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)				(953)	0	0
Interest Rate Swap \| Cash Flow Hedging \| Designated as Hedging Instrument
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)				$ 3,899	$ 3,647	$ 3,669
Crude Oil \| Swaps and Options \| Oil and Gas
Derivative [Line Items]
Notional amount - commodities \| bbl				108,000	198,000
MaximumTerm Hedged in Cash Flow Hedge				24 months	24 months
Crude Oil \| Options Held \| Oil and Gas
Derivative [Line Items]
Notional amount - commodities \| bbl				36,000
MaximumTerm Hedged in Cash Flow Hedge				12 months
Natural Gas \| Swap \| Oil and Gas
Derivative [Line Items]
Notional amount - commodities \| MMBTU				2,700,000	4,392,500
MaximumTerm Hedged in Cash Flow Hedge				24 months	24 months
Natural Gas, Distribution
Derivative [Line Items]
Notional amount - commodities \| MMBTU				2,133,000
Natural Gas, Distribution \| Cash Flow Hedging
Derivative [Line Items]
Notional amount - commodities \| MMBTU				2,138,300
Natural Gas, Distribution \| Future
Derivative [Line Items]
Notional amount - commodities \| MMBTU				14,770,000	20,580,000
Maximum Term				48 months	60 months
Natural Gas, Distribution \| Commodity Option
Derivative [Line Items]
Notional amount - commodities \| MMBTU				3,020,000	2,620,000
Maximum Term				5 months	3 months
Natural Gas, Distribution \| Basis Swap
Derivative [Line Items]
Notional amount - commodities \| MMBTU				12,250,000	18,150,000
Maximum Term				48 months	60 months
Natural Gas, Distribution \| Fixed for Float Swaps Purchased
Derivative [Line Items]
Notional amount - commodities \| MMBTU				4,622,302	0
Maximum Term				28 months	0 months
Natural Gas, Distribution \| Purchase Contract
Derivative [Line Items]
Notional amount - commodities \| MMBTU				21,504,378	0
Maximum Term				10 months	0 months
External Credit Rating, Non Investment Grade
Derivative [Line Items]
Non-investment grade credit exposure				$ 1,100
Subsequent Event \| Interest Rate Swap \| Revolving Credit Facility \| Designated as Hedging Instrument
Derivative [Line Items]
Derivative Expired During Subsequent Period			$ 50,000

Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 1,000
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Regulatory assets	296,142	$ 232,484
Gas price derivatives
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Regulatory assets	8,843	23,583
Not Designated as Hedging Instrument
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	890	0	$ 0
Sales Revenue, Net \| Not Designated as Hedging Instrument
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	(50)	0	0
Fuel, purchased power and cost of natural gas sold \| Not Designated as Hedging Instrument
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	940	0	0
Cash Flow Hedging
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	7,106	10,813	(5,664)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	(953)	0	0
Cash Flow Hedging \| Designated as Hedging Instrument
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	(38,901)	1,857	19,809
Cash Flow Hedging \| Interest Rate Swap
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	(953)	0	0
Cash Flow Hedging \| Interest Rate Swap \| Designated as Hedging Instrument
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	3,899	3,647	3,669
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(31,222)	2,888	(536)
Cash Flow Hedging \| Interest Rate Swap \| Interest Expense
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	(3,899)	(3,647)	(3,669)
Cash Flow Hedging \| Commodity derivatives \| Designated as Hedging Instrument
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	(11,005)	(14,460)	1,995
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(573)	9,782	14,681
Cash Flow Hedging \| Commodity derivatives \| Sales Revenue, Net
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	11,019	14,460	(1,995)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	$ 0	$ 0
Cash Flow Hedging \| Commodity derivatives \| Fuel, purchased power and cost of natural gas sold
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements)	(14)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	$ 0

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	$ 4,360	$ 3,441
Derivative, Liabilities, Fair Value Disclosure	2,733	2,991
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(5,995)	(12,937)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,144)	(25,141)
Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	10,355	16,378
Derivative Liabilities, Total	13,877	28,132
Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Fair Value \| Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	4,360	3,441
Derivative Liabilities, Total	2,733	2,991
Commodity Contract \| Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(3,262)	(2,293)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,144)	(24,585)
Commodity Contract \| Fair Value, Measurements, Recurring \| Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,733)	(10,644)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	(556)
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 1 \| Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	7,469	2,293
Derivative, Liabilities, Fair Value Disclosure	12,201	24,585
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 2 \| Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	2,886	10,644
Derivative, Liabilities, Fair Value Disclosure	1,586	556
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 3 \| Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract \| Fair Value \| Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	4,207	0
Derivative, Liabilities, Fair Value Disclosure	1,057	0
Commodity Contract \| Fair Value \| Fair Value, Measurements, Recurring \| Oil and Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	153	0
Derivative, Liabilities, Fair Value Disclosure	1,586	0
Interest Rate Swap \| Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	3,441
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0
Derivative, Liabilities, Fair Value Disclosure	90	2,991
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Interest Rate Swap \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Interest Rate Swap \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	3,441
Derivative, Liabilities, Fair Value Disclosure	90	2,991
Interest Rate Swap \| Fair Value, Measurements, Recurring \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	$ 0	$ 0

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 10,355	$ 16,378
Derivative Liability, Fair Value, Gross Liability	13,877	28,132
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	1,285	14,085
Derivative Liability, Fair Value, Net	1,418	3,547
Derivatives Not Designated as Hedge Instruments
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	3,075	0
Derivative Liability, Fair Value, Net	1,315	22,292
Commodity derivatives \| Designated as Hedging Instrument \| Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,161	9,981
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives \| Designated as Hedging Instrument \| Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	124	663
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives \| Designated as Hedging Instrument \| Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	1,090	465
Commodity derivatives \| Designated as Hedging Instrument \| Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	238	91
Commodity derivatives \| Derivatives Not Designated as Hedge Instruments \| Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,977	0
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives \| Derivatives Not Designated as Hedge Instruments \| Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	98	0
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives \| Derivatives Not Designated as Hedge Instruments \| Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	1,279	9,586
Commodity derivatives \| Derivatives Not Designated as Hedge Instruments \| Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	36	12,706
Interest Rate Swap \| Designated as Hedging Instrument \| Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	3,441
Derivative Asset, Fair Value, Gross Liability	0	0
Interest Rate Swap \| Designated as Hedging Instrument \| Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	90	2,835
Interest Rate Swap \| Designated as Hedging Instrument \| Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	156
Interest Rate Swap \| Derivatives Not Designated as Hedge Instruments \| Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Interest Rate Swap \| Derivatives Not Designated as Hedge Instruments \| Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 0

Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 10,355	$ 16,378
Gross Amounts Offset In Statement Of Financial Position Assets	(5,995)	(12,937)
Derivative Asset	4,360	3,441
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	13,877	28,132
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,144)	(25,141)
Derivative Liability	2,733	2,991
Contract Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	7,155	16,378
Gross Amounts Offset In Statement Of Financial Position Assets	(5,995)	(12,937)
Derivative Asset	1,160	3,441
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	12,730	28,132
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,144)	(25,141)
Derivative Liability	1,586	2,991
Contract Subject to Master Netting Arrangement \| Interest Rate Swap
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	3,441
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	3,441
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	2,991
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	2,991
Contract Not Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	3,200	0
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	3,200	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,147	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	1,147	0
Contract Not Subject to Master Netting Arrangement \| Interest Rate Swap
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	90	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	90	0
Crude Oil \| Contract Subject to Master Netting Arrangement \| Basis Swap
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	2,886	10,644
Gross Amounts Offset In Statement Of Financial Position Assets	(2,733)	(10,644)
Derivative Asset	153	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,586
Gross Amounts Offset In Statement Of Financial Position Liabilities	0
Derivative Liability	1,586
Crude Oil \| Contract Not Subject to Master Netting Arrangement \| Basis Swap
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	0
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0
Derivative Liability	0
Natural Gas, Distribution \| Contract Subject to Master Netting Arrangement \| Purchase Contract
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	4,269	2,293
Gross Amounts Offset In Statement Of Financial Position Assets	(3,262)	(2,293)
Derivative Asset	1,007	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	11,144	24,585
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,144)	(24,585)
Derivative Liability	0	0
Natural Gas, Distribution \| Contract Not Subject to Master Netting Arrangement \| Purchase Contract
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	3,200	0
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	3,200	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	1,057	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	$ 1,057	0
Natural Gas \| Contract Subject to Master Netting Arrangement \| Basis Swap
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability		556
Gross Amounts Offset In Statement Of Financial Position Liabilities		(556)
Derivative Liability		0
Natural Gas \| Contract Not Subject to Master Netting Arrangement \| Basis Swap
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability		0
Gross Amounts Offset In Statement Of Financial Position Liabilities		0
Derivative Liability		$ 0

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	$ 13,580	$ 440,861
Restricted cash - carrying amount	2,274	1,697
Notes payable	96,600	76,800
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	13,580	440,861
Restricted cash - carrying amount	2,274	1,697
Notes payable	96,600	76,800
Long-term debt, including current maturities - carrying amount	3,216,932	1,853,682
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - fair value	13,580	440,861
Restricted Cash - fair value	2,274	1,697
Notes payable - fair value	96,600	76,800
Long-term debt, including current maturities - fair value	$ 3,351,305	$ 1,992,274

Equity Units (Details) $ / shares in Units, shares in Thousands		12 Months Ended
	Nov. 23, 2015 USD ($) shares $ / shares	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Proceeds from Sale of Interest in Corporate Unit	$ 299,000,000
Equity Unit Stated Amount (usd per share) \| $ / shares	$ 50
Corporate Units Ownership Interest Percentage In Subordinated Notes	5.00%
Debt Instrument, Subordinated Notes, Stated Principal Amount	$ 1,000
Debt Instrument, Convertible, Threshold Consecutive Trading Days	20 days
Debt Instrument, Convertible, Reference Price (usd per share) \| $ / shares	$ 40.25
Stock Purchase Contract Rate	4.25%
Equity Unit, Annual Dividend Amount (usd per share) \| $ / shares	$ 2.125
Premium on Publicly-Traded Equity Units Known As Corporate Units	$ 33,000,000		$ 33,118,000
Equity units - issuance	290,030,000	$ 0	290,030,000	$ 0
Stock Purchase Contract Liability	$ 23,335,000
Black Hills Corporation
Debt Instrument [Line Items]
Long-term debt		$ 2,698,406,000	1,324,000,000
Minimum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.0572
Maximum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.2422
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Issuance of equity units \| shares	5,980
Debt Instrument, Convertible, Conversion Price (usd per share) \| $ / shares	$ 47.2938
Remarketable Junior Subordinated Notes Due 2028 \| Black Hills Corporation
Debt Instrument [Line Items]
RSN Interest Rate (percent)	3.50%	3.50%
Long-term debt	$ 299,000,000	$ 299,000,000	$ 299,000,000

Equity: At-the-Market Equity Offering Program (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016 USD ($) shares	Dec. 31, 2016 USD ($) shares
At The Market Equity Offering Program Authorized Aggregate Value	$ 200.0	$ 200.0
Common Stock
At The Market Equity Offering Program Shares Issued \| shares	218,647	1,968,738
At The Market Equity Program Proceeds from Sale of Stock	$ 13.0	$ 119.0
Payments of Stock Issuance Costs	$ 0.1	$ 1.2

Equity: Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Nov. 23, 2015	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Issuance of common stock		$ 119,990	$ 254,581
Common Stock
Class of Stock [Line Items]
Issuance of common stock, shares	6,325,000	1,968,738	6,325,000
Shares issued, price (usd per share)	$ 40.25
Issuance of common stock	$ 246,000	$ 1,969	$ 6,325

Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Shares available for grant	1,115,557
Unrecognized compensation expense	$ 13,500
Weighted-average recognition period	2 years
Stock-based compensation expense	$ 10,885	$ 4,076	$ 9,329

Equity: Stock Options (Details)	Dec. 31, 2016 shares
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercisable at end of period	119,415

Equity: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Unrecognized compensation expense	$ 13,500
Weighted-average recognition period	2 years
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested Number of Shares [Roll Forward]
Restricted Stock balance at beginning of period	202
Granted	195
Vested	(88)
Forfeited	(14)
Restricted Stock at end of period	295	202
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Balance at beginning of period (usd per share)	$ 48.96
Granted (usd per share)	53.55	$ 50.01	$ 54.34
Vested (usd per share)	48.00
Forfeited (usd per share)	51.89
Balance at end of period (usd per share)	$ 52.15	$ 48.96
Restricted Stock and RSUs, total fair value of shares vested	$ 4,602	$ 6,009	$ 6,114
Unrecognized compensation expense	$ 10,300
Weighted-average recognition period	2 years 1 month

Equity: Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$ 13,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Weighted-average recognition period	2 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Performance Share Award, Payout, Change Of Control	100.00%
Unrecognized compensation expense	$ 2,300,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	43	44
Performance Shares, Number of Shares Authorized, End of Period	53	43	44
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Granted (usd per share)		$ 54.92	$ 55.18
Blended volatility	24.00%	21.00%	23.00%
Historical volatility	50.00%
Implied volatility	50.00%
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	0	69	59
Performance Shares, Total Share-based Liabilities Paid	$ 0	$ 3,657,000	$ 3,011,000
Performance Shares, Vested in Period, Total Intrinsic Value	0	$ 7,314,000	$ 6,020,000
Target shares, value	0
Unrecognized compensation expense	$ 3,100,000
Weighted-average recognition period	1 year 9 months
Performance Shares, Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	74
Performance Shares, Granted in Period	27
Performance Shares, Forfeited in Period	0
Performance Shares, Vested in Period	(30)
Performance Shares, Number of Shares Authorized, End of Period	71	74
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at beginning of period (usd per share)	$ 47.21
Granted (usd per share)	47.76
Forfeited (usd per share)	0.00
Vested (usd per share)	35.86
Balance at end of period (usd per share)	$ 52.29	$ 47.21
Performance Shares, Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	74
Performance Shares, Granted in Period	27
Performance Shares, Forfeited in Period	0
Performance Shares, Vested in Period	(30)
Performance Shares, Number of Shares Authorized, End of Period	71	74
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at end of period (usd per share)	$ 48.05
Minimum \| Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%	0.00%	0.00%
Maximum \| Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%	200.00%	200.00%

Equity: Dividend Reinvestment and Stock Purchase Plan (Details) - Dividend Reinvestment Plan - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Percent of recent average market price	100.00%
Shares Issued	51	66
Weighted Average Price (usd per share)	$ 58.24	$ 44.79
Unissued Shares Available	356	408

Equity: Preferred Stock (Details)	Dec. 31, 2016 shares
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Equity: Noncontrolling Interest in Subsidiary (Details) - USD ($) $ in Thousands		12 Months Ended
	Apr. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Proceeds from Noncontrolling Interests		$ 216,370	$ 0	$ 0
Net income attributable to noncontrolling interest		(9,661)	0	0
Assets, Current		466,814	806,477
Property, Plant and Equipment, Gross		6,412,223	4,976,778
Liabilities, Current		527,932	406,355
Power Generation
Net income attributable to noncontrolling interest		(9,559)	0	$ 0
Property, Plant and Equipment, Gross		162,728	158,903
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Proceeds from Noncontrolling Interests	$ 216,000
Assets, Current		12,627	0
Property, Plant and Equipment, Gross		218,798	0
Liabilities, Current		$ 4,342	$ 0

Impairment of Assets (Details) $ in Thousands	12 Months Ended
Impairment of Assets (Details) $ in Thousands	Dec. 31, 2016 USD ($) $ / bbl $ / MMcf	Dec. 31, 2015 USD ($) $ / bbl $ / MMcf	Dec. 31, 2014 USD ($) $ / bbl $ / MMcf
Impaired Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 106,957	$ 249,608	$ 0
Average Natural Gas Price Per MCF, NYMEX \| $ / MMcf	2.48	2.59	4.35
Average Natural Gas Price Per MCF, Wellhead \| $ / MMcf	2.25	1.27	3.33
Average Crude Oil Price, Per Barrel, NYMEX \| $ / bbl	42.75	50.28	94.99
Average Crude Oil Price Per Barrel, Wellhead \| $ / bbl	37.35	44.72	85.80
Property, Plant and Equipment, Net	$ 4,468,989	$ 3,259,094
Oil and Gas
Impaired Assets Held and Used [Line Items]
Average Natural Gas Price Per MCF, NYMEX \| $ / MMcf	2.48	2.59
Average Natural Gas Price Per MCF, Wellhead \| $ / MMcf	2.25	1.27
Average Crude Oil Price, Per Barrel, NYMEX \| $ / bbl	42.75	50.28
Average Crude Oil Price Per Barrel, Wellhead \| $ / bbl	37.35	44.72
Property, Plant and Equipment, Net	$ 84,880	$ 206,868
Oil and Gas \| Impairment Based On Ceiling Value Of Assets
Impaired Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	92,000	$ 250,000
Oil and Gas \| Assets Not Expected To Be Utilized In Cost Of Service Gas Program
Impaired Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	14,000
Property, Plant and Equipment, Net	$ 23,000

Impairment Of Assets: Equity Investments In Unconsolidated Subsidiaries (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investment, Other than Temporary Impairment	$ 0	$ 4,405	$ 0
Oil and Gas
Equity Method Investment, Other than Temporary Impairment		$ 4,405
Willow Creek / Lodge Creek Pipeline And Gathering System \| Oil and Gas
Equity Method Investment, Ownership Percentage		25.00%
Equity Method Investment, Other than Temporary Impairment		$ 5,200
Equity Method Investment, Ownership Percentage Sold		25.00%

Operating Lease (Details) - USD ($) $ in Thousands	12 Months Ended
Operating Lease (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 9,568	$ 7,177	$ 6,932
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2017	6,739
2018	5,564
2019	4,441
2020	2,639
2021	1,652
Thereafter	$ 6,245

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current:
Federal	$ (23,820)	$ 2,549	$ (2,319)
State	(1,922)	1,319	(1,288)
Total Current	(25,742)	3,868	(3,607)
Deferred:
Federal	36,012	(23,592)	64,780
State	257	(2,323)	5,658
Tax credit amortization	(52)	(113)	(206)
Total Deferred	36,217	(26,028)	70,232
Total Current and Deferred	$ 10,475	$ (22,160)	$ 66,625

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$ 43,586	$ 58,200
Employee benefits	26,400	29,638
Federal net operating loss	217,922	252,780
Other deferred tax assets	85,907	83,485
Less: Valuation allowance	(4,304)	(9,263)
Total deferred tax assets	369,511	414,840
Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(711,293)	(820,111)
Regulatory assets	(29,092)	(49,471)
State deferred tax liability	(35,065)	(47,987)
Deferred costs	(26,121)	(18,551)
Other deferred tax liabilities	(18,519)	(14,326)
Total deferred tax liabilities	(820,090)	(950,446)
Net deferred tax liability	450,579	$ 535,606
Deferred Tax Asset - Asset Impairment
Prior Period Reclassification Adjustment	182,000
Deferred Tax Liability - Mining Development And Oil Exploration
Prior Period Reclassification Adjustment	$ 184,000

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details)		12 Months Ended
	Apr. 14, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal Statutory Rate		35.00%	35.00%	35.00%
State income tax (net of federal tax effect)		0.20%	1.00%	1.10%
Amortization of excess deferred income taxes and investment tax credits		(0.10%)	0.20%	(0.10%)
Percentage depletion		(8.20%)	3.50%	(1.00%)
Non-controlling interest		(3.60%)	(0.00%)	(0.00%)
Equity AFUDC		(1.10%)	0.30%	(0.10%)
Tax credits		(1.50%)	0.50%	(0.10%)
Transaction costs		1.10%	0.00%	0.00%
Accounting for uncertain tax positions adjustment		(6.00%)	(3.50%)	(0.10%)
Flow-through adjustments		(5.10%)	3.80%	(0.90%)
Other tax differences		0.60%	0.00%	(0.10%)
Effective Income Tax Rate, Continuing Operations		11.30%	40.80%	33.70%
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%

Income Taxes: Net Operating Loss Carryforwards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 721,075
Internal Revenue Service (IRS) \| Minimum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2019
Internal Revenue Service (IRS) \| Maximum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2036
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 616,524
State and Local Jurisdiction \| Valuation Allowance, Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Valuation Allowance	900
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 100
State and Local Jurisdiction \| Minimum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2017
State and Local Jurisdiction \| Maximum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2036

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 31,986	$ 32,192	$ 37,631
Additions for prior year tax positions	2,423	3,285	1,253
Reductions for prior year tax positions	(19,174)	(3,491)	(6,692)
Additions for current year tax positions	0	0	0
Settlements	(11,643)	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	3,592	$ 31,986	$ 32,192
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 700

Income Taxes: Interest, Penalties and Audits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense	$ 0	$ 1,800	$ 1,600
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		13,300
Deferred Income Tax Expense (Benefit)	36,217	(26,028)	70,232
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	11,643	$ 0	$ 0
Like-Kind Exchange, Aquila and IPP Transactions
Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)	125,000
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	29,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Accumulated Deferred Income Taxes	17,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Current Taxes Payable	$ 12,000

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Tax Credit Carryforward [Line Items]
Income Tax Expense (Benefit)	$ 10,475	$ (22,160)	$ 66,625
Maximum \| Foreign Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2017
Foreign Tax Authority
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 2,300
Tax Credit Carryforward, Valuation Allowance	1,700	$ 500
Internal Revenue Service (IRS) \| Settlement with Taxing Authority
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	1,800
Valuation Allowance, Deferred Tax Asset, Change in Amount	1,200
Income Tax Expense (Benefit)	600
State and Local Jurisdiction
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	6,600
State and Local Jurisdiction \| Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	19,765
State and Local Jurisdiction \| Research Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	167
State and Local Jurisdiction \| Deferred Tax Asset [Domain]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	3,600
Income Tax Expense (Benefit)	1,900
State and Local Jurisdiction \| Deferred Tax Asset [Domain] \| Utilities Group
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 1,700
State and Local Jurisdiction \| Minimum \| Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2023
State and Local Jurisdiction \| Maximum \| Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Valuation Allowance, Operating Loss Carryforwards \| State and Local Jurisdiction
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 100

Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									$ 139,590	$ 86,278	$ 73,017
Revenue	$ 463,788	$ 333,786	$ 325,441	$ 449,959	$ 318,259	$ 272,105	$ 272,254	$ 441,987	1,572,974	1,304,605	1,393,570
Fuel, purchased power and cost of natural gas sold									499,132	456,887	581,782
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes									93,106	(49,522)	197,515
Income tax benefit (expense)									(10,475)	22,160	(66,625)
Net income (loss)									82,631	(32,111)	$ 130,889
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income (loss)									3,180	4,842
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes									7,106	10,813
Income tax benefit (expense)									(2,702)	(4,271)
Net income (loss)									4,404	6,542
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income \| Interest Rate Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									(3,899)	(3,647)
Cash Flow Hedging \| Reclassification out of Accumulated Other Comprehensive Income \| Commodity Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenue									11,019	14,460
Fuel, purchased power and cost of natural gas sold									(14)	0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) \| Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									221	238
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) \| Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									(1,978)	(2,822)
Accumulated Defined Benefit Plans Adjustment \| Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes									(1,757)	(2,584)
Income tax benefit (expense)									533	884
Net income (loss)									$ (1,224)	$ (1,700)

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (9,055)	$ (15,044)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(34,883)	(9,055)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(15,780)	(20,137)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(1,985)	2,657
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(16,541)	(15,780)
Accumulated Defined Benefit Plans Adjustment \| Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,224	1,700
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(22,648)	10,831
Accumulated Other Comprehensive Income (Loss) \| Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(3,180)	(4,842)
Interest Rate Swap \| Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(341)	(4,930)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(20,302)	2,290
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(18,109)	(341)
Interest Rate Swap \| Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges \| Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	2,534	2,299
Commodity Contract \| Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	7,066	10,023
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(361)	5,884
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(233)	7,066
Commodity Contract \| Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges \| Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ (6,938)	$ (8,841)

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$ 29,082	$ 40,250	$ 52,584
Increase (decrease) in capitalized assets associated with asset retirement obligations	8,577	(518)	(5,634)
Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	(112,925)	(77,810)	(69,239)
Income taxes, net	$ (1,156)	$ (1,202)	$ (413)

Employee Benefit Plans: Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 12, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Maximum Annual Contribution Per Employee, Percent		50.00%
Employers Matching Contribution, Annual Vesting Percentage		20.00%
Employee Vesting Period		5 years
Defined Benefit Plan, Target Plan Asset Allocations		100.00%	100.00%
Equity Securities
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		28.00%	26.00%
Fixed Income Funds
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		57.00%	59.00%
Maximum
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Employers Matching Contribution, Annual Vesting Percentage		100.00%
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation	$ 22,187	$ 75,254	$ 0
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		6.87%	6.75%	6.75%
Pension Plans, Defined Benefit \| Minimum \| Equity Securities
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		40.00%
Pension Plans, Defined Benefit \| Minimum \| Fixed Income Funds
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		50.00%
Pension Plans, Defined Benefit \| Maximum \| Equity Securities
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		50.00%
Pension Plans, Defined Benefit \| Maximum \| Fixed Income Funds
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		60.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Business Combinations and Acquisitions, Benefit Obligation	$ 11,751	$ 15,091	$ 0
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		3.83%	3.00%	2.00%
Other Postretirement Benefit Plans, Defined Benefit \| Minimum \| Equity Securities
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		30.00%
Other Postretirement Benefit Plans, Defined Benefit \| Minimum \| Fixed Income Funds
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		60.00%
Other Postretirement Benefit Plans, Defined Benefit \| Maximum \| Equity Securities
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		40.00%
Other Postretirement Benefit Plans, Defined Benefit \| Maximum \| Fixed Income Funds
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Target Plan Asset Allocations		70.00%
Black Hills Corporation \| Pension Plans, Defined Benefit
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		6.75%	6.75%
Black Hills Utility Holding, Inc. Plan \| Pension Plans, Defined Benefit
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		6.75%	6.75%
SourceGas Retirement Plan \| Pension Plans, Defined Benefit
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%	0.00%

Employee Benefit Plans: Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	100.00%	100.00%
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	28.00%	26.00%
Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	5.00%	5.00%
Fixed Income Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	57.00%	59.00%
Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	2.00%	1.00%
Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	8.00%	9.00%

Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 10,000
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	14,200	$ 10,200
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	4,965	3,771
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	1,565	1,564
Defined Contribution Plan, Company Retirement
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	9,632	5,564
Defined Contribution Plan, 401K
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 9,645	$ 9,616

Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 12, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		$ 356,575	$ 377,772
Transfer from SourceGas Acquisition	$ 22,187	75,254	0
Service cost		7,619	6,093	$ 5,448
Interest cost		15,743	15,522	15,852
Actuarial (gain) loss		7,001	(28,229)
Amendments		0	0
Benefits Paid		(22,013)	(14,583)
Medicare Part D accrued		0	0
Plan participants’ contributions		0	0
Projected benefit obligation at end of year		440,179	356,575	377,772
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		40,219	41,211
Transfer from SourceGas Acquisition		0	0
Service cost		2,099	1,300
Interest cost		1,257	1,455
Actuarial (gain) loss		2,049	(2,072)
Amendments		0	0
Benefits Paid		(1,755)	(1,675)
Medicare Part D accrued		0	0
Plan participants’ contributions		0	0
Projected benefit obligation at end of year		43,869	40,219	41,211
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		48,077	49,042
Transfer from SourceGas Acquisition	$ 11,751	15,091	0
Service cost		1,757	1,808	1,700
Interest cost		1,942	1,801	1,919
Actuarial (gain) loss		2,808	(1,206)
Amendments		2,203	0
Benefits Paid		(4,965)	(3,771)
Medicare Part D accrued		0	(178)
Plan participants’ contributions		1,110	581
Projected benefit obligation at end of year		$ 68,023	$ 48,077	$ 49,042

Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	$ 288,622	$ 299,533
Transfer from SourceGas Acquisition	53,067	0
Investment income (loss)	30,819	(6,528)
Employer contributions	14,200	10,200
Retiree contributions	0	0
Benefits paid	(22,013)	(14,583)
Plan administrative expenses	0	0
Ending fair value of plan assets	364,695	288,622
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Retiree contributions	0	0
Benefits paid	(1,755)	(1,675)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	4,681	4,705
Transfer from SourceGas Acquisition	3,340	0
Investment income (loss)	256	(9)
Employer contributions	4,048	3,175
Retiree contributions	1,110	581
Benefits paid	(4,965)	(3,771)
Plan administrative expenses	0	0
Ending fair value of plan assets	$ 8,470	$ 4,681

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$ 296,142	$ 232,484
Non-current liabilities	173,682	146,459
Regulatory liabilities	206,756	153,041
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	66,640	68,915
Current liabilities	0	0
Non-current assets	0	0
Non-current liabilities	75,484	67,953
Regulatory liabilities	5,195	0
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	0	0
Current liabilities	1,583	1,568
Non-current assets	0	0
Non-current liabilities	42,286	38,651
Regulatory liabilities	0	0
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	11,401	6,464
Current liabilities	4,360	3,543
Non-current assets	21	23
Non-current liabilities	55,214	39,855
Regulatory liabilities	$ 3,419	$ 3,209

Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 416,786	$ 334,923
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	32,090	30,558
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 68,023	$ 48,077

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7,619	$ 6,093	$ 5,448
Interest cost	15,743	15,522	15,852
Expected return on assets	(23,062)	(19,470)	(18,065)
Net amortization of prior service cost	58	58	62
Recognized net actuarial loss (gain)	7,173	11,037	4,806
Settlement Expense	(10)	0	0
Net periodic benefit expense	7,541	13,240	8,103
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,335	1,380	1,498
Interest cost	1,257	1,455	1,447
Expected return on assets	0	0	0
Net amortization of prior service cost	2	2	2
Recognized net actuarial loss (gain)	829	1,081	498
Settlement Expense	0	0	0
Net periodic benefit expense	3,423	3,918	3,445
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,757	1,808	1,700
Interest cost	1,942	1,801	1,919
Expected return on assets	(279)	(131)	(85)
Net amortization of prior service cost	(428)	(428)	(428)
Recognized net actuarial loss (gain)	335	408	160
Settlement Expense	0	0	0
Net periodic benefit expense	$ 3,327	$ 3,458	$ 3,266

Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	$ 8,472	$ 8,777
Prior service cost (gain)	31	41
Total AOCI	8,503	8,818
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	2,604
Prior service cost (credit)	38
Total net periodic benefit cost expected to be recognized during calendar year 2017	2,642
Supplemental Employee Retirement Plans, Defined Benefit
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	7,132	6,339
Prior service cost (gain)	5	6
Total AOCI	7,137	6,345
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	572
Prior service cost (credit)	1
Total net periodic benefit cost expected to be recognized during calendar year 2017	573
Other Postretirement Benefit Plans, Defined Benefit
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	1,595	1,704
Prior service cost (gain)	(694)	(1,087)
Total AOCI	901	$ 617
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	325
Prior service cost (credit)	(368)
Total net periodic benefit cost expected to be recognized during calendar year 2017	$ (43)

Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	$ 2,569
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(2,191)
Effect of One Percentage Point Increase on Service and Interest Cost Components	156
Effect of One Percentage Point Decrease on Service and Interest Cost Components	$ (131)
Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2024	2024
Healthcare trend rate pre-65 \| Black Hills Corporation - All Plans
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.10%	6.35%
Healthcare trend rate pre-65 \| Black Hills Service Company
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Ultimate trend rate	4.50%	4.50%
Healthcare trend rate post-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2023	2023
Healthcare trend rate post-65 \| Black Hills Corporation - All Plans
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.10%	5.20%
Healthcare trend rate post-65 \| Black Hills Service Company
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Ultimate trend rate	4.50%	4.50%
Supplemental Employee Retirement Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	4.02%	4.28%	4.19%
Rate of Increase in Compensation Levels	5.00%	5.00%	5.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of Compensation Increase	5.00%	5.00%	5.00%
Supplemental Employee Retirement Plan \| Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.28%	4.19%	5.03%
Other Postretirement Benefit Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.96%	4.17%	3.82%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	3.83%	3.00%	2.00%
Other Postretirement Benefit Plan \| Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.18%	3.82%	4.46%
Pension Plans, Defined Benefit
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	4.27%	4.58%	4.19%
Rate of Increase in Compensation Levels	3.47%	3.51%	3.76%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.87%	6.75%	6.75%
Rate of Compensation Increase	3.42%	3.76%	3.76%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	6.75%
Pension Plans, Defined Benefit \| Black Hills Corporation Pension Plan
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	4.27%
Pension Plans, Defined Benefit \| Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.50%	4.19%	5.04%
Expected Long-term Return on Assets	6.75%	6.75%

Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 21,355
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	21,566
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	23,010
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	27,028
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	27,614
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	149,893
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	1,583
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,809
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,921
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,634
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,836
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	11,009
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	5,504
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	5,779
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	5,886
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	5,983
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	5,931
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 27,585

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Purchase Commitment
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase of Fuel, Date of Contract Expiration	Dec. 31, 2044
Busch Ranch Wind Farm \| Electric Utilities
Long-term Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
PacifiCorp Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased \| MW	50
Cost of Purchased Power \| $	$ 12,221	$ 13,990	$ 13,943
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased \| MW	50
Cost of Purchased Power \| $	$ 1,428	1,213	1,227
Happy Jack Wind Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 03, 2028
Megawatts of Capacity Purchased \| MW	30
Happy Jack Wind Purchase Power Agreement \| Renewable Wind Energy, Wyoming Electric
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power \| $	$ 3,836	3,155	3,919
Silver Sage Wind Power Purchase Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 30, 2029
Megawatts of Capacity Purchased \| MW	30
Silver Sage Wind Power Purchase Agreement \| Renewable Wind Energy, Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased \| MW	20
Cost of Purchased Power \| $	$ 4,949	4,107	4,798
Busch Ranch Wind Farm
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Oct. 16, 2037
Megawatts of Capacity Purchased \| MW	14.5
Cost of Purchased Power \| $	$ 2,071	1,734	1,998
Cargill Power Purchase Agreement
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power \| $	$ 10,995	$ 16,112	$ 9,286

Commitments And Contingencies: Long-term Purchase Commitment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Natural Gas
Long-term Purchase Commitment [Line Items]
Cost of Natural Gas Purchases	$ 31,000	$ 48,000	$ 31,000
CIG Rockies
Long-term Purchase Commitment [Line Items]
2017	5,549,427
2018	0
2019	0
2020	0
2021	0
Enable East
Long-term Purchase Commitment [Line Items]
2017	620,300
2018	584,000
2019	584,000
2020	585,600
2021	388,800
NWPL-Wyoming
Long-term Purchase Commitment [Line Items]
2017	1,208,000
2018	1,208,000
2019	720,000
2020	0
2021	0
SSTAR-TEXOK
Long-term Purchase Commitment [Line Items]
2017	457,399
2018	0
2019	0
2020	0
2021	0
Other Natural Gas Indices
Long-term Purchase Commitment [Line Items]
2017	44,913
2018	0
2019	0
2020	0
2021	$ 0

Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Power Purchase Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2017	$ 26,690
2018	8,934
2019	6,388
2020	6,388
2021	5,755
Thereafter	11,509
Transportation, Storage, Gathering And Coal Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2017	136,607
2018	120,123
2019	87,210
2020	82,247
2021	75,424
Thereafter	$ 225,765

Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility - Purchase Option, Property $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Megawatts Capacity Purchased \| MW	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2022
Asset Purchase Option \| $	$ 2.6

Commitments And Contingencies: Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2016 MW
M D U, Montana Dakota Utilities
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	25
M D U, Montana Dakota Utilities \| Maximum
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	50
City Of Gillette
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	23
Purchase Power Contract, MEAN, 10 Megawatts
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	May 31, 2023
Purchase Power Contract, MEAN, 10 Megawatts \| Neil Simpson I I
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	10
Purchase Power Contract, MEAN, 10 Megawatts \| Wygen I I I Generating Facility
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	10

Commitments And Contingencies: Related Party Lease (Details) - Power purchased - Pueblo Airport Generation	12 Months Ended
	Dec. 31, 2016 MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Lease Expiration Date	Dec. 31, 2031
Number of Megawatts Capacity Purchased	200

Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term debt	$ 544,855	$ 544,855
Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Long-term debt	$ 10,000	10,000
Long-term Debt, Maturity Date	Mar. 01, 2027
Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Long-term debt	$ 7,000	$ 7,000
Long-term Debt, Maturity Date	Sep. 01, 2021

Commitments And Contingencies: Environmental Contingencies (Details) $ in Millions	Dec. 31, 2016 USD ($)
Electric Utilities
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 4.1
Gas Utilities \| Manufactured Gas Plant
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.5
Loss Contingency, Range of Possible Loss	1.0
Accrual for Environmental Loss Contingencies, Gross	2.6
Gas Utilities \| Manufactured Gas Plant \| Minimum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	2.6
Gas Utilities \| Manufactured Gas Plant \| Maximum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	$ 6.1

Guarantees (Details) $ in Thousands	12 Months Ended
Guarantees (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 57,105
Mining \| Surety Bond
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 57,105
Guarantor Obligations, Term	Ongoing

Oil and Gas Reserves (Unaudited): Oil and Gas Narrative (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) a Gross-Well PUD_Location Mcfe State
Reserve Quantities [Line Items]
Wells in Process of Drilling \| Gross-Well	713
Gas and Oil Acreage, Leased \| a	127,919
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	0.1
Reserves Replaced	0.00%
Proved Undeveloped Reserves, Revisions of Previous Estimates	(9.4)
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Proved Developed Reserves (Energy)	0.0
PUD Developed, PUD location \| PUD_Location	0
Capital Expenditure for Proved Undeveloped Reserve \| $	$ 0.0
Prior Year
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	6
Proved Undeveloped Reserves	0.1
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.4
Added Reserves
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Commodity Prices
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	(12.3)
Reserves Dropped
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	6
Proved Undeveloped Reserves	0.1
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.4
Oil and Gas Well Performance
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	3.5
Oil and Gas Reserve Revisions, Five Year Reserve Aging Limit
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Williston Basin \| Prior Year
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	6.0
Proved Undeveloped Reserves	0.1
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.5
Williston Basin \| Reserves Dropped
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	6
Proved Undeveloped Reserves	0.1
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.5
Piceance Basin \| Prior Year
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ (0.1)
Piceance Basin \| Reserves Dropped
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.1
Piceance Basin \| Oil and Gas Reserve Revisions, Reserves Sold
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Powder River Basin \| Prior Year
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Oil and Gas
Reserve Quantities [Line Items]
Number of States in which Entity Operates \| State	9

Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Oil and Gas - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved Reserves	$ 0	$ 1,407	$ 4,881
Unproved Reserves	910	669	5,056
Exploration Costs	1,102	35,434	54,355
Development Costs	4,657	128,998	52,262
Asset Retirement Obligation Incurred	0	566	68
Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 6,669	$ 167,074	$ 116,622

Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details)	12 Months Ended
	Dec. 31, 2016 $ / bbl $ / MMcf MBbls MMcf	Dec. 31, 2015 $ / bbl $ / MMcf MBbls MMcf	Dec. 31, 2014 $ / bbl $ / MMcf MBbls MMcf
Proved Developed And Undevleoped Reserves [Roll Forward]
Average Crude Oil Price, Per Barrel, NYMEX \| $ / bbl	42.75	50.28	94.99
Average Natural Gas Price Per MCF, NYMEX \| $ / MMcf	2.48	2.59	4.35
Average Natural Gas Liquids Price Per MCF, NYMEX \| $ / MMcf	0.00	0.00	0.00
Average Crude Oil Price Per Barrel, Wellhead \| $ / bbl	37.35	44.72	85.80
Average Natural Gas Price Per MCF, Wellhead \| $ / MMcf	2.25	1.27	3.33
Average Natural Gas Liquids Price Per MCF, Wellhead \| $ / MMcf	11.92	18.96	34.81
Oil
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year \| MBbls	3,450	4,276	3,921
Production \| MBbls	(319)	(371)	(337)
Additions, Acquisitions (Sales) \| MBbls	(570)	(11)	(40)
Additions, Extensions, Discoveries (bcfe) \| MBbls	3	199	733
Reserves, Revisions of Previous Estimates \| MBbls	(322)	(643)	(1)
Balance at End of Year \| MBbls	2,242	3,450	4,276
Proved Developed Reserves (Volume) \| MBbls	2,242	3,436	3,780
Proved Undeveloped Reserve (Volume) \| MBbls	0	14	496
Natural Gas
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	73,412	65,440	63,190
Production	(9,430)	(10,058)	(7,156)
Additions, Acquisitions (Sales)	(1,291)	(828)	(61)
Additions, Extensions, Discoveries (bcfe)	52	24,462	11,003
Reserves, Revisions of Previous Estimates	(8,173)	(5,604)	(1,536)
Balance at End of Year	54,570	73,412	65,440
Proved Developed Reserves (Volume)	54,570	73,390	57,427
Proved Undeveloped Reserve (Volume)	0	22	8,013
Natural Gas Liquids
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	1,752	1,720	0
Production	(133)	(102)	(135)
Additions, Acquisitions (Sales)	(17)	0	0
Additions, Extensions, Discoveries (bcfe)	0	232	182
Reserves, Revisions of Previous Estimates	110	(98)	1,673
Balance at End of Year	1,712	1,752	1,720
Proved Developed Reserves (Volume)	1,712	1,752	1,530
Proved Undeveloped Reserve (Volume)	0	0	191
Piceance Basin
Reserve Quantities [Line Items]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses \| $ / MMcf	1.54
San Juan Basin
Reserve Quantities [Line Items]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses \| $ / MMcf	0.92
Other Basin's
Reserve Quantities [Line Items]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses \| $ / MMcf	0.53

Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Unproved oil and gas properties	$ 18,547	$ 47,254	$ 75,329
Proved oil and gas properties	1,043,558	1,008,466	807,518
Gross capitalized costs	1,062,105	1,055,720	882,847
Accumulated depreciation, depletion and amortization and valuation allowances	(1,000,091)	(888,775)	(612,012)
Net capitalized costs	$ 62,014	$ 166,945	$ 270,835

Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenue	$ 34,058	$ 43,283	$ 55,114
Production costs	17,231	19,762	22,155
Depreciation, depletion and amortization and valuation provisions	12,574	28,062	23,288
Impairment of Oil and Gas Properties	106,957	249,608	0
Total costs	136,762	297,432	45,443
Results of operations from producing activities before tax	(102,704)	(254,149)	9,671
Income tax benefit (expense)	37,916	93,743	(3,415)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$ (64,788)	$ (160,406)	$ 6,256

Oil and Gas Reserves (Unaudited): Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	$ 10,241
Exploration cost	7,416
Capitalized interest	890
Total	18,547
Current Year
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	963
Exploration cost	532
Capitalized interest	50
Total	1,545
Prior Year
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	0
Exploration cost	441
Capitalized interest	23
Total	464
More Than One Year, Less Than Two Years Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	0
Exploration cost	6,443
Capitalized interest	335
Total	6,778
More Than Two Years Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	9,278
Exploration cost	0
Capitalized interest	482
Total	9,760
Oil and Gas
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 900	$ 1,000	$ 1,000

Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 246,221	$ 295,173	$ 675,973
Future production costs	(166,248)	(146,552)	(245,180)
Future development costs, including plugging and abandonment	(18,333)	(24,833)	(45,123)
Future income tax expense	0	0	(29,523)
Future net cash flows	61,640	123,788	356,147
10% annual discount for estimated timing of cash flows	(26,574)	(44,760)	(173,125)
Standardized measure of discounted future net cash flows	$ 35,066	$ 79,028	$ 183,022	$ 159,425

Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure - beginning of year	$ 79,028	$ 183,022	$ 159,425
Sales and transfers of oil and gas produced, net of production costs	(4,314)	(29,948)	(32,139)
Net changes in prices and production costs	(32,698)	(127,199)	(28,544)
Extensions, discoveries and improved recovery, less related costs	0	15,718	17,582
Changes in future development costs	1,825	(7,387)	3,195
Development costs incurred during the period	0	27,211	2,079
Revisions of previous quantity estimates	(7,477)	(6,941)	23,722
Accretion of discount	7,903	18,870	18,437
Net change in income taxes	0	5,682	19,265
Purchases of reserves	0	0	0
Sales of reserves	(9,201)	0	0
Standardized measure - end of year	$ 35,066	$ 79,028	$ 183,022

Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Information [Line Items]
Revenue	$ 463,788	$ 333,786	$ 325,441	$ 449,959	$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 1,572,974	$ 1,304,605	$ 1,393,570
Operating income (loss)	55,289	58,409	35,298	73,590	197	(2,044)	(38,858)	70,500	222,586	29,795	263,868
Income (loss) from continuing operations	21,414	17,884	3,283	40,050	(14,176)	(9,943)	(41,842)	33,850
Net income (loss) available for common stock	$ 18,168	$ 14,131	$ 669	$ 40,002	$ (14,176)	$ (9,943)	$ (41,842)	$ 33,850	$ 72,970	$ (32,111)	$ 130,889
Earnings (loss) per share, Basic (usd per share)	$ 0.34	$ 0.27	$ 0.01	$ 0.78	$ (0.30)	$ (0.22)	$ (0.94)	$ 0.76	$ 1.41	$ (0.71)	$ 2.95
Earnings (loss) per share, Diluted (usd per share)	0.33	0.26	0.01	0.77	(0.30)	(0.22)	(0.94)	0.76	1.37	(0.71)	2.93
Dividends per share paid (usd per share)	$ 0.420	$ 0.420	$ 0.420	$ 0.420	$ 0.405	$ 0.405	$ 0.405	$ 0.405	$ 1.68	$ 1.62	$ 1.56
Impairment Of Oil And Gas Properties, Net Of Tax	$ 34,000	$ 7,900	$ 16,000	$ 8,800	$ 44,000	$ 36,000	$ 66,000	$ 14,000
Business Combination, Acquisition Related Costs, Net Of Tax	$ 5,500	$ 4,100	$ 4,100	$ 15,000	$ 3,700	$ 2,800	$ 500
Common Stock \| Maximum
Selected Quarterly Financial Information [Line Items]
Share Price (usd per share)	$ 62.83	$ 64.58	$ 63.53	$ 61.13	$ 47.51	$ 47.27	$ 52.96	$ 53.37
Common Stock \| Minimum
Selected Quarterly Financial Information [Line Items]
Share Price (usd per share)	$ 54.76	$ 56.86	$ 56.16	$ 44.65	$ 40.00	$ 36.81	$ 43.48	$ 47.88

Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Movement in Valuation Allowances and Reserves [Roll Forward]

Allowance for Doubtful Accounts, Balance at Beginning of Year

$ 1,741

$ 1,516

$ 1,237

Allowance for Doubtful Accounts, Adjustments

2,158

^[1]

Allowance for Doubtful Accounts, Charged to Cost and Expense

2,704

3,860

4,470

Allowance for Doubtful Accounts, Recoveries and Other Additions

4,915

4,132

4,233

Allowance for Doubtful Accounts, Write-Offs and Other Deductions

(9,126)

(7,767)

(8,424)

Allowance for Doubtful Accounts, Balance at End of Year

$ 2,392

$ 1,741

$ 1,516

[1]	Represents allowance balances added with the SourceGas acquisition.

Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 364,695	$ 288,622	$ 299,533
Pension Plans, Defined Benefit \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	319,816	251,733
Pension Plans, Defined Benefit \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| AXA Equitable General Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,325	1,072
Pension Plans, Defined Benefit \| AXA Equitable General Fixed Income \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| AXA Equitable General Fixed Income \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,325	1,072
Pension Plans, Defined Benefit \| AXA Equitable General Fixed Income \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5,307	1,556
Pension Plans, Defined Benefit \| Common Collective Trust - Cash and Cash Equivalents \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Cash and Cash Equivalents \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5,307	1,556
Pension Plans, Defined Benefit \| Common Collective Trust - Cash and Cash Equivalents \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	101,020	74,885
Pension Plans, Defined Benefit \| Common Collective Trust - Equity \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Equity \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	101,020	74,885
Pension Plans, Defined Benefit \| Common Collective Trust - Equity \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	209,815	172,016
Pension Plans, Defined Benefit \| Common Collective Trust - Fixed Income \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Fixed Income \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	209,815	172,016
Pension Plans, Defined Benefit \| Common Collective Trust - Fixed Income \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17,912	13,347
Pension Plans, Defined Benefit \| Common Collective Trust - Real Estate \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Common Collective Trust - Real Estate \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,349	2,204
Pension Plans, Defined Benefit \| Common Collective Trust - Real Estate \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	29,316	25,746
Pension Plans, Defined Benefit \| Hedge Funds \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Hedge Funds \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Pension Plans, Defined Benefit \| Hedge Funds \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	8,470	4,681	$ 4,705
Other Postretirement Benefit Plans, Defined Benefit \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,265	0
Other Postretirement Benefit Plans, Defined Benefit \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	7,205	4,681
Other Postretirement Benefit Plans, Defined Benefit \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Other Postretirement Benefit Plans, Defined Benefit \| Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	111
Other Postretirement Benefit Plans, Defined Benefit \| Cash and Cash Equivalents \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	111
Other Postretirement Benefit Plans, Defined Benefit \| Cash and Cash Equivalents \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Other Postretirement Benefit Plans, Defined Benefit \| Cash and Cash Equivalents \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Other Postretirement Benefit Plans, Defined Benefit \| Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,154
Other Postretirement Benefit Plans, Defined Benefit \| Equity Securities \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,154
Other Postretirement Benefit Plans, Defined Benefit \| Equity Securities \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Other Postretirement Benefit Plans, Defined Benefit \| Equity Securities \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Other Postretirement Benefit Plans, Defined Benefit \| Common Collective Trust, Money Market Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,732	4,681
Other Postretirement Benefit Plans, Defined Benefit \| Common Collective Trust, Money Market Fund \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Other Postretirement Benefit Plans, Defined Benefit \| Common Collective Trust, Money Market Fund \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,732	4,681
Other Postretirement Benefit Plans, Defined Benefit \| Common Collective Trust, Money Market Fund \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Other Postretirement Benefit Plans, Defined Benefit \| Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,473
Other Postretirement Benefit Plans, Defined Benefit \| Intermediate - Term Bond \| Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Other Postretirement Benefit Plans, Defined Benefit \| Intermediate - Term Bond \| Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,473
Other Postretirement Benefit Plans, Defined Benefit \| Intermediate - Term Bond \| Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0
Net Asset Value \| Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	44,879	36,889
Net Asset Value \| Pension Plans, Defined Benefit \| AXA Equitable General Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Net Asset Value \| Pension Plans, Defined Benefit \| Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Net Asset Value \| Pension Plans, Defined Benefit \| Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Net Asset Value \| Pension Plans, Defined Benefit \| Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Net Asset Value \| Pension Plans, Defined Benefit \| Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	15,563	11,143
Net Asset Value \| Pension Plans, Defined Benefit \| Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 29,316	$ 25,746