Black Hills (BKH) 10-K 25 Feb 15 2014 FY Annual report Financial data

Document_Information_Document

Document Information Document (USD $)	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1130464
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		44,676,072
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$2,696,775,649

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue:
Total revenue	$1,393,570	$1,275,852	$1,173,884
Utilities -
Fuel, purchased power and cost of natural gas sold	581,782	492,147	407,066
Operations and maintenance	270,954	261,919	242,367
Non-regulated energy operations and maintenance	88,141	83,762	85,830
Gain on sale of operating assets	0	0	-29,129	[1]
Depreciation, depletion and amortization	148,083	141,217	154,632
Impairment of long-lived assets	0	0	26,868	[2]
Taxes - property, production and severance	43,580	40,012	40,487
Other operating expenses	500	1,243	2,052
Total operating expenses	1,133,040	1,020,300	930,173
Operating income	260,530	255,552	243,711
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	-73,017	-113,979	-117,754
Allowance for funds used during construction - borrowed	1,075	1,130	3,462
Capitalized interest	982	1,061	682
Unrealized gain (loss) on interest rate swaps, net	0	30,169	1,882
Interest income	1,925	1,723	1,957
Allowance for funds used during construction - equity	994	607	540
Other expense	-377	-694	-71
Other income	2,065	1,971	2,486
Total other income (expense)	-66,353	-78,012	-106,816
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes	194,177	177,540	136,895
Equity in earnings (loss) of unconsolidated subsidiaries	-1	-86	10
Income tax benefit (expense)	-65,395	-61,608	-48,400
Income (loss) from continuing operations	128,781	115,846	88,505
Income (loss) from discontinued operations, net of tax	0	-884	-6,977
Net income (loss) available for common stock	128,781	114,962	81,528
Earnings (loss) per share, Basic -
Income (loss) from continuing operations (usd per share)	$2.90	$2.62	$2.02
Income (loss) from discontinued operations (usd per share)	$0	($0.02)	($0.16)
Total income (loss) per share, Basic (usd per share)	$2.90	$2.60	$1.86
Earnings (loss) per share, Diluted -
Income (loss) from continuing operations (usd per share)	$2.89	$2.61	$2.01
Income (loss) from discontinued operations (usd per share)	$0	($0.02)	($0.16)
Total income (loss) per share, Diluted (usd per share)	$2.89	$2.59	$1.85
Weighted average common shares outstanding:
Basic (in shares)	44,394	44,163	43,820
Diluted (in shares)	44,598	44,419	44,073
Utilities Group [Member]
Revenue:
Total revenue	1,300,969	1,191,133	1,064,813
Non Regulated Energy Group [Member]
Revenue:
Total revenue	$92,601	$84,719	$109,071
[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Oil and Gas includes a ceiling test impairment (see Note 12).

Consolidated_Statement_of_Comp

Consolidated Statement of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income (loss) available for common stock	$128,781	$114,962	$81,528
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $5,004, $(3,813) and $296, respectively)	-10,590	8,237	-542
Benefit plan liability adjustments - prior service (costs) (net of tax of $(17), $185 and $86, respectively)	237	-406	-157
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(348), $(971) and $0, respectively)	646	1,820	0
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $76, $88 and $0, respectively)	-141	-165	0
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(5,239), $(2,445) and $887, respectively)	8,906	4,534	-1,268
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $(2,344), $(2,016) and $534, respectively)	3,320	4,046	-643
Other comprehensive income (loss), net of tax	2,378	18,066	-2,610
Comprehensive income (loss)	$131,159	$133,028	$78,918

Statement_of_Comprehensive_Inc

Statement of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Benefit plan liability adjustments - net gain (loss), Tax	$5,004	($3,813)	$296
Benefit plan liability adjustments - prior service (costs), Tax	-17	185	86
Reclassification adjustment of benefit plan liability - net gain (loss) tax	-348	-971	0
Reclassification adjustment of benefit plan liability - prior service cost, tax	76	88	0
Fair value adjustment on derivatives designated as cash flow hedges, Tax	-5,239	-2,445	887
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax	($2,344)	($2,016)	$534

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$21,218	$7,841
Restricted cash and equivalents	2,056	2
Accounts receivable, net	189,992	177,573
Materials, supplies and fuel	91,191	88,478
Derivative assets, current	0	717
Income tax receivable, net	2,053	1,460
Deferred income tax assets, net, current	48,288	18,889
Regulatory assets, current	74,396	24,451
Other current assets	24,842	25,877
Total current assets	454,036	345,288
Investments	17,294	16,697
Property, plant and equipment	4,563,400	4,259,445
Less accumulated depreciation and depletion	-1,324,025	-1,269,148
Total property, plant and equipment, net	3,239,375	2,990,297
Other assets:
Goodwill	353,396	353,396
Intangible assets, net	3,176	3,397
Derivative assets, non-current	0	0
Regulatory assets, non-current	183,443	138,197
Other assets, non-current	29,086	27,906
Total other assets, non-current	569,101	522,896
TOTAL ASSETS	4,279,806	3,875,178
Current liabilities:
Accounts payable	124,139	130,416
Accrued liabilities	170,115	151,277
Derivative liabilities, current	3,340	3,474
Regulatory liabilities, current	3,687	10,727
Notes payable	75,000	82,500
Current maturities of long-term debt	275,000	0
Total current liabilities	651,281	378,394
Long-term debt, net of current maturities	1,267,589	1,396,948
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	523,716	432,287
Derivative liabilities, non-current	2,680	5,614
Regulatory liabilities, non-current	145,144	109,429
Benefit plan liabilities	158,966	111,479
Other deferred credits and other liabilities	154,406	133,279
Total deferred credits and other liabilities	984,912	792,088
Commitments and contingencies (See Notes 5, 6, 7, 8, 13, 17, 18 and 19)
Stockholders’ equity:
Common stock $1 par value; 100,000,000 shares authorized; issued: 44,714,072 and 44,550,239 shares, respectively	44,714	44,550
Additional paid-in capital	748,840	742,344
Retained earnings	599,389	540,244
Treasury stock at cost - 42,226 and 50,877 shares, respectively	-1,875	-1,968
Accumulated other comprehensive income (loss)	-15,044	-17,422
Total stockholders’ equity	1,376,024	1,307,748
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$4,279,806	$3,875,178

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Common Stock, Par or Stated Value Per Share	$1	$1
Common Stock, Shares, Outstanding	44,671,846	44,499,362
Treasury Stock, Shares	42,226	50,877
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	44,714,072	44,550,239

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income (loss) available for common stock	$128,781	$114,962	$81,528
(Income) loss from discontinued operations, net of tax	0	884	6,977
Income (loss) from continuing operations	128,781	115,846	88,505
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	148,083	141,217	154,632
Deferred financing cost amortization	2,127	6,763	5,555
Impairment of long-lived assets	0	0	26,868	[1]
Gain on sale of operating assets	0	0	-29,129	[2]
Stock compensation	9,329	12,595	8,271
Unrealized (gain) loss on interest rate swaps, net	0	-30,169	-1,882
Deferred income taxes	69,002	63,784	39,716
Employee benefit plans	14,814	22,194	20,973
Other adjustments, net	14,415	9,826	4,929
Change in certain operating assets and liabilities:
Materials, supplies and fuel	-4,563	-5,770	6,343
Accounts receivable, unbilled revenues and other current assets	-65,091	-13,921	13,739
Accounts payable and other current liabilities	16,027	15,336	-10,713
Contributions to defined benefit pension plans	-10,200	-12,500	-25,350
Other operating activities, net	733	312	-6,670
Net cash provided by operating activities of continuing operations	323,457	325,513	295,787
Net cash provided by (used in) operating activities of discontinued operations	0	-884	21,184
Net cash provided by operating activities	323,457	324,629	316,971
Investing activities:
Property, plant and equipment additions	-398,494	-354,749	-349,129
Proceeds from sale of assets	0	0	253,791
Other investing activities	-2,653	5,471	-180
Net cash provided by (used in) investing activities of continuing operations	-401,147	-349,278	-95,518
Proceeds from sale of business operations	0	0	107,511
Net cash provided by (used in) investing activities of discontinued operations	0	0	-824
Net cash provided by (used in) investing activities	-401,147	-349,278	11,169
Financing activities:
Dividends paid on common stock	-69,636	-67,587	-65,262
Common stock issued	3,251	4,354	4,726
Short-term borrowings - issuances	396,250	337,650	203,753
Short-term borrowings - repayments	-403,750	-532,150	-271,753
Long-term debt - issuance	160,000	800,000	0
Long-term debt - repayments	-12,200	-445,906	-240,077
De-designated interest rate swap settlement	0	-63,939	0
Other financing activities	17,152	-15,394	-2,833
Net cash provided by (used in) financing activities of continuing operations	91,067	17,028	-371,446
Net cash provided by (used in) financing activities of discontinued operations	0	0	0
Net cash provided by (used in) financing activities	91,067	17,028	-371,446
Net change in cash and cash equivalents	13,377	-7,621	-43,306
Cash and cash equivalents:
Cash and cash equivalents beginning of year	7,841	15,462	58,768	[3]
Cash and cash equivalents end of year	$21,218	$7,841	$15,462
[1]	Oil and Gas includes a ceiling test impairment (see Note 12).
[2]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[3]	Cash and cash equivalents include cash of discontinued operations of $37 million at December 31, 2011.

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (USD $)	Dec. 31, 2011
In Millions, unless otherwise specified
Statement of Cash Flows [Abstract]
Cash and Cash Equivalents of Discontinued Operations	$37

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
In Thousands, except Share data, unless otherwise specified
Stockholders' Equity Attributable to Parent Period Start at Dec. 31, 2011	$1,209,336	$43,958	($970)	$722,623	$476,603	($32,878)
Treasury Stock, Shares, Period Start at Dec. 31, 2011			32,766
Shares, Issued Period Start at Dec. 31, 2011		43,957,502
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	81,528	0	0	0	81,528	0
Other comprehensive income (loss), net of tax	-2,610	0	0	0	0	-2,610
Dividends on common stock, shares		0	0
Dividends on common stock	-65,262	0	0	0	-65,262	0
Share-based compensation, shares		219,946	39,016
Share-based compensation	6,040	220	-1,275	7,095	0	0
Tax effect of share-based compensation	117	0	0	117	0	0
Dividend reinvestment and stock purchase plan, shares		100,741	0
Dividend reinvestment and stock purchase plan	3,382	100	0	3,282	0	0
Other stock transactions, shares		0	0
Other stock transactions	-22	0	0	-22	0	0
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$1.48
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2012	1,232,509	44,278	-2,245	733,095	492,869	-35,488
Treasury Stock, Shares, Period End at Dec. 31, 2012			71,782
Shares, Issued Period End at Dec. 31, 2012		44,278,189
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	114,962	0	0	0	114,962	0
Other comprehensive income (loss), net of tax	18,066	0	0	0	0	18,066
Dividends on common stock, shares		0	0
Dividends on common stock	-67,587	0	0	0	-67,587	0
Share-based compensation, shares		190,172	-20,905
Share-based compensation	5,867	190	277	5,400	0	0
Tax effect of share-based compensation	410	0	0	410	0	0
Dividend reinvestment and stock purchase plan, shares		66,878	0
Dividend reinvestment and stock purchase plan	3,129	67	0	3,062	0	0
Other stock transactions, shares		15,000	0
Other stock transactions	392	15	0	377	0	0
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$1.52
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2013	1,307,748	44,550	-1,968	742,344	540,244	-17,422
Treasury Stock, Shares, Period End at Dec. 31, 2013	50,877		50,877
Shares, Issued Period End at Dec. 31, 2013		44,550,239
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	128,781	0	0	0	128,781	0
Other comprehensive income (loss), net of tax	2,378	0	0	0	0	2,378
Dividends on common stock, shares		0	0
Dividends on common stock	-69,636	0	0	0	-69,636	0
Share-based compensation, shares		111,507	-8,651
Share-based compensation	4,415	112	93	4,210	0	0
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation	-499	0	0	-499	0	0
Dividend reinvestment and stock purchase plan, shares		52,326	0
Dividend reinvestment and stock purchase plan	2,878	52	0	2,826	0	0
Other stock transactions, shares		0	0
Other stock transactions	-41	0	0	-41	0	0
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$1.56
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2014	$1,376,024	$44,714	($1,875)	$748,840	$599,389	($15,044)
Treasury Stock, Shares, Period End at Dec. 31, 2014	42,226		42,226
Shares, Issued Period End at Dec. 31, 2014		44,714,072

Business_Description_And_Signi

Business Description And Significant Accounting Policies:	12 Months Ended
	Dec. 31, 2014
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 diversified energy company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, operates in two primary business groups: Utilities and Non-regulated Energy.
	The Utilities Group includes our Electric Utilities and Gas Utilities segments. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric and the electric and natural gas utility operations of Cheyenne Light, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyoming and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas.
	The Non-regulated Energy Group includes our Power Generation, Coal Mining and Oil and Gas segments. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Oil and Gas, 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. These businesses are aggregated for reporting purposes as Non-regulated Energy.
	On February 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being reclassified as discontinued operations. See Note 21 for additional information.
	For further descriptions of our reportable business segments, see Note 4.
	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 4.
	Our Consolidated Statements of Income 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 3 for additional information.
	As a result of the sale of our Energy Marketing segment, amounts associated with this segment have been reclassified as discontinued operations on the accompanying Consolidated Financial Statements. See Note 21 for additional information.
	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 Utilities Group 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 unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group 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 against amounts due 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):
	2014	Accounts Receivable, Trade			Unbilled Revenue			Less Allowance for Doubtful Accounts			Accounts Receivable, net
	Electric Utilities	$	59,714		$	26,474		$	(722	)	$	85,466
	Gas Utilities	47,394			45,546			(781		)	92,159
	Power Generation	1,369			—			—			1,369
	Coal Mining	3,151			—			—			3,151
	Oil and Gas	5,305			—			(13		)	5,292
	Corporate	2,555			—			—			2,555
	Total	$	119,488		$	72,020		$	(1,516	)	$	189,992
	2013	Accounts Receivable, Trade			Unbilled Revenue			Less Allowance for Doubtful Accounts			Accounts Receivable, net
	Electric Utilities	$	52,437		$	23,823		$	(666	)	$	75,594
	Gas Utilities	49,162			41,195			(558		)	89,799
	Power Generation	1,722			—			—			1,722
	Coal Mining	1,711			—			—			1,711
	Oil and Gas	8,156			—			(13		)	8,143
	Corporate	604			—			—			604
	Total	$	113,792		$	65,018		$	(1,237	)	$	177,573
	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 tax 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):
		31-Dec-14			31-Dec-13
	Materials and supplies	$	49,555		$	50,196
	Fuel - Electric Utilities	6,637			6,213
	Natural gas in storage held for distribution	34,999			32,069
	Total materials, supplies and fuel	$	91,191		$	88,478
	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
	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.
	The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus cost of removal, 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, a unit-of-production methodology based on plant hours run is used.
	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. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 21 for further discussion.
	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 a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2014 or 2013. See Note 12 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 elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 20.
	Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report on 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 this annual review of goodwill and indefinite lived intangible assets as of November 30 each year (or more frequently if impairment indicators arise).
We performed our annual goodwill impairment tests as of November 30, 2014. 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.
Goodwill at our Electric and Gas Utilities primarily arose from the acquisition of one regulated electric and four regulated gas utilities in the Aquila Transaction. This goodwill from the Aquila Transaction was allocated approximately $246 million, or 72%, to Colorado Electric and $94 million, or 28%, to the Gas Utilities. We believe that the goodwill amount reflects the value of the relatively stable, long-lived cash flows of the regulated gas utility business, considering the regulatory environment and market growth potential and the long-lived cash flow and rate base growth opportunities at our electric utility in Colorado. Goodwill balances were as follows (in thousands):
	Electric Utilities			Gas Utilities			Power Generation			Total
Ending balance at December 31, 2012	$	250,487		$	94,144		$	8,765		$	353,396
Additions (adjustments)	—			—			—			—
Ending balance at December 31, 2013	$	250,487		$	94,144		$	8,765		$	353,396
Additions (adjustments)	—			—			—			—
Ending balance at December 31, 2014	$	250,487		$	94,144		$	8,765		$	353,396
Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized over 20 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
	2014			2013			2012
Intangible assets, net, beginning balance	$	3,397		$	3,620		$	3,843
Additions (adjustments)	—			—			—
Amortization expense*	(221		)	(223		)	(223		)
Intangible assets, net, ending balance	$	3,176		$	3,397		$	3,620
_________________
*	Amortization expense for existing intangible assets is expected to be $0.2 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. 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 7.
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.
Utilities Segment:
•	The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant since these instruments are not traded on an exchange.
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.
Additional information is included in Note 9.
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, and 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 regulated electric and gas 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.
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 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.
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 Utilities Group follows accounting standards for regulated operations and reflects 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)	31-Dec-14			31-Dec-13
Regulatory assets
Deferred energy and fuel cost adjustments - current (a)(d)	1	$	23,820		$	16,775
Deferred gas cost adjustments (a)(d)	2	37,471			4,799
Gas price derivatives (a)	7	18,740			7,567
AFUDC (b)	45	12,358			12,315
Employee benefit plans (c) (e)	12	97,126			67,059
Environmental (a)	subject to approval	1,314			1,800
Asset retirement obligations (a)	44	3,287			3,266
Bond issue cost (a)	23	3,276			3,419
Renewable energy standard adjustment (a)	5	9,622			14,186
Flow through accounting (c)	35	25,887			20,916
Decommissioning costs	10	12,484			—
Other regulatory assets (a)	15	12,454			10,546
		$	257,839		$	162,648
Regulatory liabilities
Deferred energy and gas costs (a)	1	$	6,496		$	11,708
Employee benefit plans (c) (e)	12	53,139			34,431
Cost of removal (a)	44	78,249			64,970
Other regulatory liabilities (c)	25	10,947			9,047
		$	148,831		$	120,156
__________
(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. Increases in the current year balances as of December 31, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. 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)	Increases are due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Deferred Energy and Fuel Cost Adjustments - 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 7-year term represents the maximum forward term hedged.
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 accumulated other comprehensive income, including costs being amortized from the Aquila Transaction.
Environmental - Environmental is 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 7 for additional details.
Bond Issue Costs - Bond issue costs are 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.
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. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached with respect to Black Hills Power in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. 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 repairs for tax purposes, but are capitalized for book purposes.
Decommissioning Costs - Black Hills Power and Colorado Electric received approval for regulatory treatment on the remaining net book values of their decommissioned coal plants in 2014. These balances were in Property, Plant and Equipment in 2013.
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. 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 liability method in accounting for income taxes. Under the 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. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.
It is our policy to apply the flow-through method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. 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. Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property.
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.
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 14 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 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):
	31-Dec-14			31-Dec-13			31-Dec-12
Income (loss) from continuing operations	$	128,781		$	115,846		$	88,505
Weighted average shares - basic	44,394			44,163			43,820
Dilutive effect of:
Equity compensation	204			256			250
Other	—			—			3
Weighted average shares - diluted	44,598			44,419			44,073
Income (loss) from continuing operations, per share - Diluted	$	2.89		$	2.61		$	2.01
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):
	31-Dec-14		31-Dec-13		31-Dec-12
Equity compensation	81		22		163
Anti-dilutive shares excluded from computation of earnings (loss) per share	81		22		163
Discontinued Operations
On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. In accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. See Note 21 for additional information.
Recently Issued and Adopted Accounting Standards
We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.
Revenue from Contracts with Customers, ASU 2014-09
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.
Recently Issued Accounting Pronouncements and Legislation
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforwards Exists, ASU 2013-11
In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after December 15, 2013 and interim periods within those years, and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard did not have any impact on our financial position, results of operations or cash flows.
Final Tangible Property Regulations, Treasury Decision 9636
In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations had the effect of a change in law and as a result, the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We implemented all of the provisions of the final regulations with the filing of the 2013 federal income tax return in September 2014. The adoption of the final regulations did not have a material impact on our consolidated financial statements.

Property_Plant_And_Equipment

Property, Plant And Equipment:	12 Months Ended
	Dec. 31, 2014
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):
	Utilities Group	2014			2013				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	$	1,125,845	45	$	951,138		45	25	65
	Electric transmission	284,032		49	238,542			50	40	65
	Electric distribution	718,342		44	666,589			44	15	65
	Plant acquisition adjustment (a)	4,870		32	4,870			32	32	32
	General	152,982		21	138,263			22	3	60
	Capital lease - plant in service (b)	261,441		20	261,441			20	20	20
	Total electric plant in service	$	2,547,512		$	2,260,843
	Construction work in progress	49,700			203,760
	Total electric plant	2,597,212			2,464,603
	Less accumulated depreciation and amortization	484,406			472,970
	Electric plant net of accumulated depreciation and amortization	$	2,112,806		$	1,991,633
	_____________
	(a) The plant acquisition adjustment is included in rate base and is being recovered with 16 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.
		2014			2013				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	$	13	37	$	13		37	37	37
	Gas transmission	24,090		54	24,984			54	53	57
	Gas distribution	557,405		46	507,318			46	41	56
	General	90,085		19	85,841			19	16	22
	Total gas plant in service	671,593			618,156
	Construction work in progress	16,072			9,417
	Total gas plant	687,665			627,573
	Less accumulated depreciation and amortization	92,035			84,679
	Gas plant net of accumulated depreciation and amortization	$	595,630		$	542,894
	2014														Lives ( in years)
	Non-regulated Energy	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	$	153,779	$	2,262		$	156,041		$	47,704		$	108,337	33	2	40
	Coal Mining	145,619		3,748			149,367			90,629			58,738		15	2	59
	Oil and Gas	962,395		—			962,395			612,736			349,659		24	3	25
		$	1,261,793	$	6,010		$	1,267,803		$	751,069		$	516,734
	2013														Lives ( in years)
	Non-regulated Energy	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	$	143,026	$	10,491		$	153,517		$	43,069		$	110,448	36	2	40
	Coal Mining	149,067		1,156			150,223			86,306			63,917		14	2	59
	Oil and Gas	852,384		—			852,384			585,334			267,050		24	3	25
		$	1,144,477	$	11,647		$	1,156,124		$	714,709		$	441,415
	2014														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	$	5,524	$	5,196		$	10,720		$	(3,485	)	$	14,205	11	5	30
	___________
	(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
	2013														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	$	5,498	$	5,647		$	11,145		$	(3,210	)	$	14,355	6	2	30
	___________
	(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.

Jointly_Owned_Facilities

Jointly Owned Facilities:	12 Months Ended
	Dec. 31, 2014
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. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
	•	Black Hills Power 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. Black Hills Power 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 Black Hills Power with coal for its share of the Wyodak Plant, our Coal 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.
	•	Black Hills Power 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 - 200 MW West to East and 200 MW from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.
	•	Black Hills Power 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 Coal Mining subsidiary supplies coal to Wygen III for the life of the plant.
	•	Colorado Electric owns 50% of the Busch Ranch Wind Project 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 project 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. 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 Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations.
	At December 31, 2014, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
		Plant in Service		Construction Work in Progress		Accumulated Depreciation
	Wyodak Plant	$	110,123	$	1,201	$	53,816
	Transmission Tie	$	19,648	$	—	$	4,976
	Wygen I	$	109,040	$	1,765	$	31,852
	Wygen III	$	136,220	$	29	$	13,811
	Busch Ranch Wind Project	$	18,590	$	—	$	1,573

Business_Segments_Information

Business Segments Information:	12 Months Ended
	Dec. 31, 2014
Segment Reporting Information, Additional Information [Abstract]
Business Segments Information	BUSINESS SEGMENTS INFORMATION
	Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. Primarily, all of our operations and assets are located within the United States.
	On February 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being reclassified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been reclassified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 21.
	Segment information was as follows (in thousands):
	Total Assets (net of inter-company eliminations) as of December 31,	2014			2013
	Utilities:
	Electric (a)	$	2,748,680		$	2,525,947
	Gas	906,922			805,617
	Non-regulated Energy:
	Power Generation (a)	76,945			95,692
	Coal Mining	74,407			78,825
	Oil and Gas	366,247			288,366
	Corporate	106,605			80,731
	Total assets	$	4,279,806		$	3,875,178
	__________________
	(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.
	Capital Expenditures and Asset Acquisitions(a) for the years ended December 31,	2014			2013
	Utilities:
	Electric Utilities	$	193,199		$	222,262
	Gas Utilities	70,528			63,205
	Non-regulated Energy:
	Power Generation	2,379			13,533
	Coal Mining	6,676			5,528
	Oil and Gas	109,439			64,687
	Corporate	9,046			10,319
	Total capital expenditures and asset acquisitions	$	391,267		$	379,534
	_________________
	(a)	Includes accruals for property, plant and equipment.
	Property, Plant and Equipment as of December 31,	2014			2013
	Utilities:
	Electric Utilities (a)	$	2,597,212		$	2,464,603
	Gas Utilities	687,665			627,573
	Non-regulated Energy:
	Power Generation (a)	156,041			153,517
	Coal Mining	149,367			150,223
	Oil and Gas	962,395			852,384
	Corporate	10,720			11,145
	Total property, plant and equipment	$	4,563,400		$	4,259,445
	_______________
	(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.
		Consolidating Income Statement
	Year ended December 31, 2014	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
	Revenue	$	683,201		$	617,768		$	6,401		$	31,086		$	55,114		$	—		$	—		$	1,393,570
	Inter-company revenue	14,110			—			81,157			32,272			—			222,460			(349,999		)	—
	Total revenue	697,311			617,768			87,558			63,358			55,114			222,460			(349,999		)	1,393,570
	Fuel, purchased power and cost of natural gas sold	314,573			380,852			—			—			—			116			(113,759		)	581,782
	Operations and maintenance	165,641			132,635			33,126			41,172			42,659			213,415			(225,473		)	403,175
	Depreciation, depletion and amortization	79,424			26,499			4,540			10,276			27,584			7,690			(7,930		)	148,083
	Operating income (loss)	137,673			77,782			49,892			11,910			(15,129		)	1,239			(2,837		)	260,530
	Interest expense	(53,402		)	(15,725		)	(4,351		)	(493		)	(2,603		)	(50,299		)	55,913			(70,960		)
	Interest income	4,615			441			682			59			918			48,969			(53,759		)	1,925
	Other income (expense), net	1,164			34			(6		)	2,275			183			61,605			(62,574		)	2,681
	Income tax benefit (expense)	(30,498		)	(20,663		)	(17,701		)	(3,299		)	5,998			24			744			(65,395		)
	Income (loss) from continuing operations	$	59,552		$	41,869		$	28,516		$	10,452		$	(10,633	)	$	61,538		$	(62,513	)	$	128,781
		Consolidating Income Statement
	Year ended December 31, 2013	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
	Revenue	$	651,445		$	539,689		$	4,648		$	25,186		$	54,884		$	—		$	—		$	1,275,852
	Inter-company revenue	13,863			—			78,389			31,442			—			220,620			(344,314		)	—
	Total revenue	665,308			539,689			83,037			56,628			54,884			220,620			(344,314		)	1,275,852
	Fuel, purchased power and cost of natural gas sold	294,048			310,463			—			—			—			125			(112,489		)	492,147
	Operations and maintenance	159,961			126,073			30,186			39,519			40,365			202,809			(211,977		)	386,936
	Depreciation, depletion and amortization	77,704			26,381			5,091			11,523			21,770			11,624			(12,876		)	141,217
	Operating income (loss)	133,595			76,772			47,760			5,586			(7,251		)	6,062			(6,972		)	255,552
	Interest expense (a)	(61,537		)	(25,234		)	(21,178		)	(641		)	(2,253		)	(85,195		)	84,250			(111,788		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			30,169			—			30,169
Interest income	5,277			976			785			10			1,639			69,760			(76,724		)	1,723
Other income (expense), net	633			(60		)	1			2,304			108			41,453			(42,641		)	1,798
Income tax benefit (expense)	(25,834		)	(19,747		)	(11,080		)	(932		)	3,545			(7,778		)	218			(61,608		)
Income (loss) from continuing operations	$	52,134		$	32,707		$	16,288		$	6,327		$	(4,212	)	$	54,471		$	(41,869	)	$	115,846
________________
(a)	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).
	Consolidating Income Statement
Year ended December 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Total revenue	626,966			454,081			79,389			57,778			79,072			196,453			(319,855		)	1,173,884
Fuel, purchased power and cost of natural gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets (a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711
Interest expense(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505
________________
(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
(b)	Oil and Gas includes a ceiling test impairment (see Note 12).
(c)	Corporate includes a make-whole provision from early repayment of long-term debt.

LongTerm_Debt

Long-Term Debt:	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
Long-term Debt	LONG-TERM DEBT
	Long-term debt outstanding was as follows (dollars in thousands) as of:
			Interest Rate at
		Due Date	31-Dec-14	31-Dec-14			31-Dec-13
	Corporate
	Senior unsecured notes due 2023	30-Nov-23	4.25%	$	525,000		$	525,000
	Unamortized discount on Senior unsecured note due 2023 (a)			(2,164		)	—
	Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
	Corporate term loan due 2015 (b)	June 19, 2015	1.31%	275,000			275,000
	Total Corporate Debt			997,836			1,000,000
	Electric Utilities
	First Mortgage Bonds due 2044	20-Oct-44	4.43%	85,000			—
	First Mortgage Bonds due 2044	20-Oct-44	4.53%	75,000			—
	First Mortgage Bonds due 2032	15-Aug-32	7.23%	75,000			75,000
	First Mortgage Bonds due 2039	1-Nov-39	6.13%	180,000			180,000
	Unamortized discount on First Mortgage Bonds due 2039			(102		)	(107		)
	Pollution control revenue bonds due 2024	1-Oct-24	5.35%	—			12,200
	First Mortgage Bonds due 2037	20-Nov-37	6.67%	110,000			110,000
	Industrial development revenue bonds due 2021, variable rate (c)	1-Sep-21	0.09%	7,000			7,000
	Industrial development revenue bonds due 2027, variable rate (c)	March 1, 2027	0.09%	10,000			10,000
	Series 94A Debt, variable rate (c)	June 1, 2024	0.75%	2,855			2,855
	Total Electric Utilities			544,753			396,948
	Total long-term debt			1,542,589			1,396,948
	Less current maturities			275,000			—
	Long-term debt, net of current maturities			$	1,267,589		$	1,396,948
	_______________
	(a)	Discount on note initially reflected in deferred financing costs at December 31, 2013.
	(b)	Variable interest rate, based on LIBOR plus a spread.
	(c)	Variable interest rate.
	Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
	2015	$	275,000
	2016	$	—
	2017	$	—
	2018	$	—
	2019	$	—
	Thereafter	$	1,269,855
	Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2014.
	Substantially all of the tangible utility property of Black Hills Power and Cheyenne Light is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of Black Hills Power and Cheyenne Light may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by Black Hills Power and Cheyenne Light are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.
	Debt Transactions
	On October 1, 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Black Hills Power issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 and Cheyenne Light issued $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. Proceeds from Black Hills Power’s bond sale also funded the early redemption of its 5.35% $12 million pollution control revenue bonds, originally due October 1, 2024.
	On November 19, 2013, we entered into a $525 million, 4.25% senior unsecured note expiring on November 30, 2023. The proceeds from this new debt were used to:
	•	Redeem our $250 million senior unsecured 9.0% notes originally due on May 15, 2014. This repayment occurred on December 19, 2013, for approximately $261 million which included a make-whole provision of approximately $8.5 million and accrued interest which are included in Interest expense on the accompanying Consolidated Statements of Income;
	•	Repay our variable interest rate Black Hills Wyoming project financing with a remaining balance of approximately $87 million originally due on December 9, 2016, as well as the interest rate swaps designated to this project financing of $8.5 million which is included in Interest expense on the accompanying Consolidated Statements of Income;
	•	Settle the $250 million notional de-designated interest rate swaps for approximately $64 million;
	•	Pay down approximately $55 million of the Revolving Credit Facility; and
	•	Remainder was used for general corporate purposes.
	On June 21, 2013, we entered into a new long-term Corporate Term Loan for $275 million expiring on June 19, 2015. The proceeds from this new term loan were used to repay the $150 million corporate term loan due on June 24, 2013, the $100 million corporate term loan due on September 30, 2013 and approximately $25 million in short-term borrowing under our Revolving Credit Facility. The covenants of the new term loan are substantially the same as the Revolving Credit Facility. At December 31, 2014, the cost of borrowing under this term loan was 1.3125% (LIBOR plus a margin of 1.125%).
	Amortization Expense
	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
		Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at				Amortization Expense for the years ended December 31,
		31-Dec-14				2014			2013		2012
	Senior unsecured notes due 2023	$	3,908			$	653		$	86	$	—
	Senior unsecured notes due 2014	$	—			$	—		$	635	$	462
	Senior unsecured notes due 2020	$	926			$	167		$	167	$	167
	First mortgage bonds due 2044 (Black Hills Power) (a)	$	711			$	6		$	—	$	—
	First mortgage bonds due 2044 (Cheyenne Light) (a)	$	654			$	6		$	—	$	—
	First mortgage bonds due 2032	$	584			$	33		$	33	$	33
	First mortgage bonds due 2039	$	1,885			$	76		$	76	$	76
	First mortgage bonds due 2037	$	705			$	31		$	31	$	31
	Black Hills Wyoming project financing due 2016 (b)	$	—			$	—		$	3,177	$	1,037
	Other	$	483			$	53		$	57	$	57
	_____________
	(a)	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.
	(b)	This project financing was repaid in 2013 and the deferred financing costs were written off.
Dividend Restrictions
Our credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of December 31, 2014, 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, 2014:
•	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, 2014, the restricted net assets at our Utilities Group were approximately $315 million.

Notes_Payable

Notes Payable:	12 Months Ended
	Dec. 31, 2014
Notes Payable [Abstract]
Notes Payable	NOTES PAYABLE
	Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2014, 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):
		Balance Outstanding at
		31-Dec-14		31-Dec-13
	Revolving Credit Facility	$	75,000	$	82,500
	Revolving Credit Facility
	On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P and Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, from May 29, 2014 through December 31, 2014; a reduction of 0.25% for each method of borrowing as compared to the previous arrangement. Borrowings under the facility are primarily Eurodollar based. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating, a reduction of 0.025% compared to the prior arrangement.
	As of December 31, 2014 and 2013, we had outstanding letters of credit totaling approximately $35 million and approximately $22 million, respectively.
	Deferred financing costs on the facility of $3.8 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. Upon entering into the Revolving Credit Facility in 2012, $1.5 million of deferred financing costs relating to the previous credit facility was written off through Interest expense. The deferred financing costs on the new facility are being amortized as follows (in thousands):
		Deferred Financing Costs Remaining on Balance Sheets as of		Amortization Expense for the years ended December 31,
		31-Dec-14		2014			2013		2012
	Revolving Credit Facility	$	1,779	$	616		$	752	$	2,187
	Debt Covenants
	Our Revolving Credit Facility and our new Term Loan require compliance with the following financial covenant at the end of each quarter:
		At December 31, 2014		Covenant Requirement
	Recourse leverage ratio	55	%	Less than	65	%

Asset_Retirement_Obligations

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2014
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 Coal Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment 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):
		31-Dec-13		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates (a) (b)			31-Dec-14
	Electric Utilities	$	6,922	$	—	$	(85	)	$	175	$	—		$	7,012
	Gas Utilities	274		—		—			17		—			291
	Coal Mining	20,627		345		—			951		(2,785		)	19,138
	Oil and Gas	24,028		68		(932		)	1,043		(3,262		)	20,945
	Total	$	51,851	$	413	$	(1,017	)	$	2,186	$	(6,047	)	$	47,386
		31-Dec-12		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates			31-Dec-13
	Electric Utilities	$	6,981	$	—	$	—		$	168	$	(227	)	$	6,922
	Gas Utilities	259		—		—			15		—			274
	Coal Mining	20,286		3		(714		)	1,052		—			20,627
	Oil and Gas	23,022		143		(1,903		)	1,450		1,316			24,028
	Total	$	50,548	$	146	$	(2,617	)	$	2,685	$	1,089		$	51,851
	_____________________
	(a)	The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability.
	(b)	The Oil and Gas Revision to Prior Estimates was due to a change in useful well lives used in calculating the estimated liability.
	We also have legally required AROs related to certain assets within our electric and gas utility 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

Risk Management Activities:	12 Months Ended
	Dec. 31, 2014
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 with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and
	•	Interest rate risk associated with our variable rate debt and our other short-term and long-term debt instruments.
	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, 2014, our credit exposure included a $0.6 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 and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 9.
	Oil and Gas Exploration and Production
	We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.
	To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.
	The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying 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, terms of our commodity derivatives and the derivative balances for our Oil and Gas segment reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:
		31-Dec-14						31-Dec-13
		Crude oil futures, swaps and options			Natural gas futures, swaps and options			Crude oil futures, swaps and options			Natural gas futures, swaps and options
	Notional (a)	334,500			6,582,500			412,500			7,082,500
	Maximum terms in months (b)	1			1			3			1
	Derivative assets, current	$	—		$	—		$	55		$	—
	Derivative assets, non-current	$	—		$	—		$	—		$	—
	Derivative liabilities, current	$	—		$	—		$	—		$	—
	Derivative liabilities, non-current	$	—		$	—		$	—		$	—
	________________________
	(a)	Crude in Bbls, gas in MMBtu.
	(b)	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
	Based on December 31, 2014 market prices, a $10 million gain would be reclassified from AOCI during 2015. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.
	Utilities
	The operations of our utilities, including power purchase arrangements where our 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 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. 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. Accordingly, the hedging activity is recognized in the Consolidated Statements of Income (Loss) or the Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.
	The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:
		31-Dec-14			31-Dec-13
		Notional (MMBtus)		Maximum Term (months) (a)	Notional (MMBtus)		Maximum Term (months) (a)
	Natural gas futures purchased	19,370,000		72	17,930,000		84
	Natural gas options purchased	4,020,000		8	3,890,000		8
	Natural gas basis swaps purchased	12,005,000		60	14,785,000		60
	__________
	(a) Term reflects the maximum forward period hedged.
	We had the following derivative balances related to the hedges in our Utilities reflected in our Consolidated Balance Sheets as of (in thousands):
		31-Dec-14			31-Dec-13
	Derivative assets, current	$	—		$	662
	Derivative assets, non-current	$	—		$	—
	Derivative liabilities, current	$	—		$	—
	Derivative liabilities, non-current	$	—		$	—
	Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	18,740		$	7,567
	Financing Activities
	We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. 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:
		31-Dec-14			31-Dec-13
		Interest Rate Swaps (a)			Interest Rate Swaps (a)
	Notional	$	75,000		$	75,000
	Weighted average fixed interest rate	4.97		%	4.97		%
	Maximum terms in years	2			3
	Derivative liabilities, current	$	3,340		$	3,474
	Derivative liabilities, non-current	$	2,680		$	5,614
	___________________
	(a)	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related borrowings.
	Based on December 31, 2014 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $3.3 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. 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) for years ended were as follows (in thousands):
		31-Dec-14
	Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	(536	)	Interest expense	$	3,669			$	—
	Commodity derivatives	14,681			Revenue	1,995				—
	Total	$	14,145			$	5,664			$	—
	31-Dec-13
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	7,935		Interest expense	$	6,989			$	—
Commodity derivatives	(956		)	Revenue	(927		)		—
Total	$	6,979			$	6,062			$	—
	31-Dec-12
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—
Derivatives Not Designated as Hedge Instruments
The impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31 were as follows (in thousands):
		2014			2013			2012
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
Interest rate swaps - unrealized (a)	Unrealized gain (loss) on interest rate swap, net	$	—		$	30,169		$	1,882
Interest rate swaps - realized (a)	Interest expense	—			(12,902		)	(12,959		)
		$	—		$	17,267		$	(11,077	)
_______________
(a)	These interest rate swaps were settled in the fourth quarter of 2013.

Fair_Value_Measurements

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2014
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 2014 or 2013. 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 10. 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, 2014
		Level 1			Level 2			Level 3				Cash Collateral and Counterparty Netting			Total
	Assets:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			8,599			—				(8,599		)	—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			6,558			—				(6,558		)	—
	Commodity derivatives - Utilities	—			2,389			—				(2,389		)	—
	Total	$	—		$	17,546		$	—			$	(17,546	)	$	—
	Liabilities:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			—			—				—			—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			473			—				(473		)	—
	Commodity derivatives - Utilities	—			19,303			—				(19,303		)	—
	Interest rate swaps	—			6,020			—				—			6,020
	Total	$	—		$	25,796		$	—			$	(19,776	)	$	6,020
		As of December 31, 2013
		Level 1			Level 2			Level 3				Cash Collateral and Counterparty Netting			Total
	Assets:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			130			—				(75		)	55
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			815			—				(815		)	—
	Commodity derivatives - Utilities	—			3,030			—				(2,368		)	662
	Total	$	—		$	3,975		$	—			$	(3,258	)	$	717
	Liabilities:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			1,229			—				(1,229		)	—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			531			—				(531		)	—
	Commodity derivatives - Utilities	—			9,100			—				(9,100		)	—
	Interest rate swaps	—			9,088			—				—			9,088
	Total	$	—		$	19,948		$	—			$	(10,860	)	$	9,088
	Fair Value Measures by Balance Sheet Classification
	As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis, aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. However, the amounts do not include net cash collateral on deposit in margin accounts at December 31, 2014 and 2013, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 8.
	The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):
			2014						2013
		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	$	10,391		$	—		$	248		$	—
	Commodity derivatives	Derivative assets - non-current	4,766			—			698			—
	Commodity derivatives	Derivative liabilities - current	—			185			—			1,541
	Commodity derivatives	Derivative liabilities - non-current	—			288			—			219
	Interest rate swaps	Derivative liabilities - current	—			3,340			—			3,474
	Interest rate swaps	Derivative liabilities - non-current	—			2,680			—			5,614
	Total derivatives designated as hedges		$	15,157		$	6,493		$	946		$	10,848
	Derivatives not designated as hedges:
	Commodity derivatives	Derivative assets - current	$	—		$	—		$	662		$	—
	Commodity derivatives	Derivative assets - non-current	—			—			—			—
	Commodity derivatives	Derivative liabilities - current	—			8,032			—			—
	Commodity derivatives	Derivative liabilities - non-current	—			8,882			—			6,732
	Interest rate swaps	Derivative liabilities - current	—			—			—			—
	Interest rate swaps	Derivative liabilities - non-current	—			—			—			—
	Total derivatives not designated as hedges		$	—		$	16,914		$	662		$	6,732
	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, 2014 and December 31, 2013, 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, 2014 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 - Crude Basis Swaps	$	8,599		$	(8,599	)	$	—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	6,558			(6,558		)	—
Utilities	2,389			(2,389		)	—
Total derivative assets subject to a master netting agreement or similar arrangement	17,546			(17,546		)	—
Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	—			—			—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	—			—			—
Utilities	—			—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	—			—			—
Total derivative assets	$	17,546		$	(17,546	)	$	—
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 - Crude Basis Swaps	$	—		$	—		$	—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	473			(473		)	—
Utilities	19,303			(19,303		)	—
Interest Rate Swaps	—			—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	19,776			(19,776		)	—
Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	—			—			—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	—			—			—
Utilities	—			—			—
Interest Rate Swaps	6,020			—			6,020
Total derivative liabilities not subject to a master netting agreement or similar arrangement	6,020			—			6,020
Total derivative liabilities	$	25,796		$	(19,776	)	$	6,020
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2013 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 - Crude Basis Swaps	$	75		$	(75	)	$	—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	815			(815		)	—
Utilities	3,030			(2,368		)	662
Total derivative assets subject to a master netting agreement or similar arrangement	3,920			(3,258		)	662
Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	55			—			55
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	—			—			—
Utilities	—			—			—
Total derivative assets not subject to a master netting agreement or similar arrangement	55			—			55
Total derivative assets	$	3,975		$	(3,258	)	$	717
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 - Crude Basis Swaps	$	1,229		$	(1,229	)	$	—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	531			(531		)	—
Utilities	9,100			(9,100		)	—
Interest Rate Swaps	—			—			—
Total derivative liabilities subject to a master netting agreement or similar arrangement	10,860			(10,860		)	—
Not subject to a master netting agreement or similar arrangement:
Commodity derivative:
Oil and Gas - Crude Basis Swaps	—			—			—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	—			—			—
Utilities	—			—			—
Interest Rate Swaps	9,088			—			9,088
Total derivative liabilities not subject to a master netting agreement or similar arrangement	9,088			—			9,088
Total derivative liabilities	$	19,948		$	(10,860	)	$	9,088
Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2014 were (in thousands):
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets			Cash Collateral Received			Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—		$	—		$	—
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			—			—
		$	—		$	—		$	—
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities			Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—		$	(4,392	)	$	(4,392	)
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			(3,093		)	(3,093		)
Interest Rate Swaps	Counterparty F	6,020			—			6,020
		$	6,020		$	(7,485	)	$	(1,465	)
Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2013 were (in thousands):
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets			Cash Collateral Received			Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—		$	—		$	—
Oil and Gas	Counterparty B	55			—			55
Utilities	Counterparty A	662			—			662
		$	717		$	—		$	717
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities			Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—		$	(1,631	)	$	(1,631	)
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			(3,390		)	(3,390		)
Interest Rate Swap	Counterparty F	9,088			—			9,088
		$	9,088		$	(5,021	)	$	4,067

Fair_Value_Of_Financial_Instru

Fair Value Of Financial Instruments:	12 Months Ended
	Dec. 31, 2014
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 9, were as follows at December 31 (in thousands):
		2014				2013
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Cash and cash equivalents (a)	$	21,218	$	21,218	$	7,841	$	7,841
	Restricted cash and equivalents (a)	$	2,056	$	2,056	$	2	$	2
	Notes payable (a)	$	75,000	$	75,000	$	82,500	$	82,500
	Long-term debt, including current maturities (b)	$	1,542,589	$	1,734,555	$	1,396,948	$	1,491,422
	_______________
	(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
	(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.
	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 5 and Note 6.

Stock

Stock:	12 Months Ended
	Dec. 31, 2014
Common Stocks, Including Additional Paid in Capital, Net of Discount [Abstract]
Stock	STOCK
	Equity Compensation Plans
	Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 522,831 shares available to grant at December 31, 2014.
	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, 2014, total unrecognized compensation expense related to non-vested stock awards was approximately $9.4 million and is expected to be recognized over a weighted-average period of 1.6 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended December 31 (in thousands):
		2014			2013			2012
	Stock-based compensation expense	$	9,329		$	12,595		$	8,271
	Stock Options
	We have granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest proportionately over 3 years and expire 10 years after the grant date.
	A summary of the status of the stock options at December 31, 2014 was as follows:
		Shares		Weighted-Average Exercise Price				Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
		(in thousands)						(in years)	(in thousands)
	Balance at beginning of period	61		$	33.25
	Granted (a)	81		54.29
	Forfeited/canceled	—		—
	Expired	—		—
	Exercised	(8	)	30.87
	Balance at end of period	134		$	46.12			8.2	$	1,027
	Exercisable at end of period	46		$	32.63			6.5	$	944
	___________________________
	(a)	The grant date fair value of the 2014 awards was $12.58 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.1% risk free interest rate, 29.4% expected price volatility, 2.9% expected dividend yield and a 7 year expected life.
	The table below provides details of our option plans at December 31 (in thousands):
		2014			2013			2012
	Summary of Stock Options
	Unrecognized compensation expense	$	816		$	130		$	218
	Intrinsic value of options exercised (a)	$	199		$	789		$	623
	Net cash received from exercise of options	$	237		$	2,046		$	2,839
	Tax benefit realized from exercise of shares (b)	$	70		$	276		$	218
	_____________________
	(a)	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
	(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.
	As of December 31, 2014, the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 2.1 years.
	Restricted Stock
	The fair value of restricted stock 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 at December 31, 2014, was as follows:
		Restricted Stock		Weighted-Average Grant Date Fair Value
		(in thousands)
	Restricted Stock at beginning of period	262		$	36.76
	Granted	99		54.34
	Vested	(114	)	35.25
	Forfeited	(14	)	43.17
	Restricted Stock at end of period	233		$	44.6
	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)
	2014	$	54.34		$	6,114
	2013	$	40.56		$	5,842
	2012	$	34.99		$	3,781
	As of December 31, 2014, there was $6.1 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.7 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 $2.1 million at December 31, 2014 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
	1-Jan-12	January 1, 2012 - December 31, 2014	64	0%	200%
	1-Jan-13	January 1, 2013 - December 31, 2015	61	0%	200%
	1-Jan-14	January 1, 2014 - December 31, 2016	44	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 (b)
		Shares					Shares		31-Dec-14
		(in thousands)					(in thousands)
	Performance Shares balance at beginning of period	93		$	31.34		93
Granted	23		55.18			23
Forfeited	(1	)	40.12			(1	)
Vested	(31	)	25.92			(31	)
Performance Shares balance at end of period	84		$	39.58		84		$	82.42
_____________________
(a)	The grant date fair values for the performance shares granted in 2014, 2013 and 2012 were determined by Monte Carlo simulation using a blended volatility of 23%, 20% and 21%, 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.
(b)	The weighted-average fair value for the liability portion at December 31, 2014 was determined by the actual performance for the 2012 to 2014 performance period at the top of the peer group resulting in a 200% of target payout, and determined by Monte Carlo simulations for the 2013 to 2015 performance period and 2014 to 2016 performance period projecting a 157% and 51% of target payouts, respectively.
The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:
	Weighted Average Grant Date Fair Value
31-Dec-14	$	55.18
31-Dec-13	$	35.85
31-Dec-12	$	32.26
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, 2011 to December 31, 2013	2014	59		$	3,011		$	6,020
January 1, 2010 to December 31, 2012	2013	63		$	2,267		$	4,533
January 1, 2009 to December 31, 2011	2012	—		$	—		$	—
On January 27, 2015, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2012 through December 31, 2014 performance period was at the 100th percentile of its peer group and confirmed a payout equal to 200% of target shares, valued at $7.3 million. The payout was fully accrued at December 31, 2014.
As of December 31, 2014, there was $2.5 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.5 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):
	2014			2013
Shares Issued	52			67
Weighted Average Price	$	54.99		$	46.78
Unissued Shares Available	474			286
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.

Impairment_Of_LongLived_Assets

Impairment Of Long-Lived Assets:	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Impairment of Long-lived Assets	IMPAIRMENT OF 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 in the second quarter of 2012, we recorded a $27 million non-cash impairment of oil and gas assets included in the Oil and Gas segment. 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. When this non-cash impairment occurred, commodity prices during the second quarter of 2012 were; for natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.

Operating_Leases

Operating Leases:	12 Months Ended
	Dec. 31, 2014
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):
		2014		2013		2012
	Rent expense	$	6,932	$	7,169	$	6,839
	The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
	2015	$	9,962
	2016	$	2,045
	2017	$	1,852
	2018	$	1,829
	2019	$	1,632
	Thereafter	$	3,735

Income_Taxes

Income Taxes:	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES
	Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
		2014			2013			2012
	Current:
	Federal	$	(2,319	)	$	(2,003	)	$	4,972
	State	(1,288		)	(173		)	3,712
		(3,607		)	(2,176		)	8,684
	Deferred:
	Federal	63,645			56,963			39,876
	State	5,563			7,033			68
	Tax credit amortization	(206		)	(212		)	(228		)
		69,002			63,784			39,716
		$	65,395		$	61,608		$	48,400
	The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
		2014			2013
	Deferred tax assets:
	Regulatory liabilities	$	49,243		$	33,172
	Employee benefits	26,714			28,724
	Federal net operating loss	213,466			166,095
	Asset impairment	55,067			55,124
	Other deferred tax assets(a)	76,005			59,078
	Less: Valuation allowance	(5,017		)	(1,806		)
	Total deferred tax assets	415,478			340,387
	Deferred tax liabilities:
	Accelerated depreciation, amortization and other plant-related differences	(679,911		)	(598,415		)
	Regulatory assets	(25,340		)	(24,581		)
	Mining development and oil exploration	(97,198		)	(69,799		)
	State deferred tax liability	(37,489		)	(30,293		)
	Deferred costs	(35,284		)	(15,593		)
	Other deferred tax liabilities	(15,684		)	(15,104		)
	Total deferred tax liabilities	(890,906		)	(753,785		)
	Net deferred tax liability	$	(475,428	)	$	(413,398	)
	_______________
	(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.
	The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
		2014		2013		2012
	Federal statutory rate	35	%	35	%	35	%
	State income tax (net of federal tax effect)	1.1		2.4		2
	Amortization of excess deferred income taxes and investment tax credits	(0.1	)	(0.1	)	(0.2	)
	Percentage depletion in excess of cost	(1.0	)	(1.0	)	(1.3	)
	Equity AFUDC	(0.1	)	—		—
	Tax credits	(0.1	)	(0.5	)	—
	Accounting for uncertain tax positions adjustment	(0.1	)	0.7		0.8
	Flow-through adjustments (a)	(0.9	)	(0.9	)	(1.3	)
	Other tax differences	(0.1	)	(0.9	)	0.4
		33.7	%	34.7	%	35.4	%
	_________________________
	(a)	The flow-through adjustments relate 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. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred in 2010. 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 a tax benefit consistent with the flow-through method.
	At December 31, 2014, 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		$	618,195			2019	to	2034
	State Net Operating Loss Carryforward		$	513,418			2015	to	2034
	As of December 31, 2014, we had a $1.0 million valuation allowance against the state NOL carryforwards. Our 2014 analysis of the ability to utilize such NOLs resulted in an increase of the valuation allowance of approximately $0.5 million, which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a decrease in taxable income for 2014 due to the enactment of TIPA. 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, 2012	$	49,327
	Additions for prior year tax positions	111
	Reductions for prior year tax positions	(8,906		)
	Additions for current year tax positions	151
	Settlements	—
	Ending balance at December 31, 2012	40,683
	Additions for prior year tax positions	1,526
	Reductions for prior year tax positions	(4,578		)
	Additions for current year tax positions	—
Settlements	—
Ending balance at December 31, 2013	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
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.8 million.
We recognized interest expense of $1.6 million, $1.6 million and $1.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.
We had approximately $11.5 million and $9.9 million of accrued interest (before tax effect) associated with income taxes at December 31, 2014 and 2013, respectively.
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 IRS in August 2014 related to the like-kind exchange transaction described below and research and development credits and deductions claimed with respect to certain costs and projects. We are also currently under examination by the IRS for the 2010 to 2012 tax years.
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 has challenged our position with respect to the like-kind exchange and it is reasonably possible that the total unrecognized tax benefits attributable to such transaction could change significantly due to a settlement with the IRS that is anticipated to occur on or before December 31, 2015. However, based on the information currently available, it is difficult to determine any reasonable estimate of the financial statement impact including the impact on the effective tax rate.
Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2014, we had foreign tax credit carryforwards of approximately $0.5 million, which expire between 2015 and 2017.
As of December 31, 2014, we had a $0.5 million valuation allowance against the foreign tax credit carryforwards. In addition, the carryforward balance reflects the expected utilization of approximately $1.8 million of foreign tax credits to be included as computational adjustments upon finalization of our current IRS examination covering tax years 2007 to 2009. Such foreign tax credits have been 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.
State tax credits have been generated and are available to offset future state income taxes. At December 31, 2014, we had the following state tax credit carryforwards (in thousands):
State Tax Credit Carryforwards				Expiration Year
Investment tax credit	$	14,793		2023	to	2025
Research and development	$	155		No expiration
As of December 31, 2014, we had a $3.5 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 $2.7 million of which approximately $1.5 million resulted in an increase to tax expense. The remaining $1.2 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 projected impact of lower commodity prices related to oil and natural gas on forecasted taxable income. 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

Other Comprehensive Income:	12 Months Ended
	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income	OTHER COMPREHENSIVE INCOME
	The components of the reclassification adjustments for the period, net of tax, included in Other comprehensive income were as follows (in thousands):
		Location on the Consolidated Statements of Income	Amount Reclassified from AOCI
			31-Dec-14			31-Dec-13
	Gains and losses on cash flow hedges:
	Interest rate swaps	Interest expense	$	3,669		$	6,989
	Commodity contracts	Revenue	1,995			(927		)
			5,664			6,062
	Income tax	Income tax benefit (expense)	(2,344		)	(2,016		)
	Total reclassification adjustments related to cash flow hedges, net of tax		$	3,320		$	4,046
	Amortization of defined benefit plans:
	Prior service cost	Utilities - Operations and maintenance	$	(102	)	$	(125	)
		Non-regulated energy operations and maintenance	(115		)	(128		)
	Actuarial gain (loss)	Utilities - Operations and maintenance	630			1,693
		Non-regulated energy operations and maintenance	364			1,098
			777			2,538
	Income tax	Income tax benefit (expense)	(272		)	(883		)
	Total reclassification adjustments related to defined benefit plans, net of tax		$	505		$	1,655
	Balances by classification included within Accumulated other comprehensive income (loss) 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, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)
	Other comprehensive income (loss)	1,695			10,531			(9,848		)	2,378
	As of December 31, 2014	$	(4,930	)	$	10,023		$	(20,137	)	$	(15,044	)
		Derivatives Designated as Cash Flow Hedges
		Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	As of December 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)
	Other comprehensive income (loss)	9,688			(1,108		)	9,486			18,066
	As of December 31, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)

Supplemental_Disclosure_of_Cas

Supplemental Disclosure of Cash flow Information:	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
	Years ended December 31,	2014			2013			2012
		(in thousands)
	Non-cash investing activities and financing from continuing operations -
	Property, plant and equipment acquired with accrued liabilities	$	52,584		$	59,811		$	35,556
	Increase (decrease) in capitalized assets associated with asset retirement obligations	$	(5,634	)	$	1,235		$	5,743
	Cash (paid) refunded during the period for continuing operations-
	Interest (net of amount capitalized)	$	(69,239	)	$	(108,361	)	$	(116,593	)
	Income taxes, net	$	(413	)	$	(4,573	)	$	(3,027	)

Employee_Benefit_Plans

Employee Benefit Plans:	12 Months Ended
	Dec. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS
	Defined Contribution Plans
	We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan 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) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides 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.
	Funded Status of Benefit Plans
	The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, these costs are recoverable in our rates, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax (see Note 1). The measurement date for all plans is December 31, 2014. As of December 31, 2014, the unfunded status of our Defined Benefit Pension Plans was $78 million; the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $41 million; and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $44 million.
	Defined Benefit Pension Plans (Pension Plans)
	We have two defined benefit pension plans. Our BHC Pension Plan covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC, BHEP and Cheyenne Light. The Black Hills Utility Holdings, Inc. Pension Plan covers certain eligible employees of Black Hills Energy. 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. Both Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria.
	Pension Plan assets are held in a Master Trust. Each Plan holds 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 long-term rate of return for investments was 6.75% and 7.25% for the 2014 and 2013 plan years, respectively. Our Pension Plan funding policy is in accordance with the federal government’s funding requirements.
	In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of January 1, 2012. Additionally, effective October 1, 2012, the Cheyenne Light Pension Plan was merged into the BHC Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.
	Plan Assets
	The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows:
		2014		2013
	Equity	27	%	26	%
	Real estate	5		4
	Fixed income	58		58
	Cash	2		1
	Hedge funds	8		11
	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
	We sponsor three retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans is pre-funded via VEBAs. Effective January 1, 2014, health care coverage for Medicare-eligible retirees will be provided through an individual market health care exchange for BHC and Black Hills Utility Holdings retirees.
	Plan Assets
	We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Energy Plan provides for partial pre-funding via VEBAs. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of Black Hills Energy located in the states of Kansas and Iowa. We do not pre-fund the Postretirement Healthcare Plans for those employees outside Kansas and Iowa.
	Plan Contributions
	Contributions to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. 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):
		2014			2013
	Defined Contribution Plan
	Company Retirement Contribution	$	4,187		$	2,775
	Matching contributions - Defined Contribution Plans	$	9,254		$	8,524
		2014			2013
	Defined Benefit Plans
	Defined Benefit Pension Plans	$	10,200		$	12,500
	Non-Pension Defined Benefit Postretirement Healthcare Plans	$	3,163		$	5,123
	Supplemental Non-Qualified Defined Benefit Plans	$	1,553		$	1,345
	While we do not have required contributions, we expect to make approximately $10 million in contributions to our Defined Benefit Pension Plans in 2015.
	Fair Value Measurements
	As required by accounting standards for Compensation - Retirement Benefits, 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	31-Dec-14
		Level 1				Level 2				Level 3				Total
	AXA Equitable General Fixed Income	$	—			$	541			$	—			$	541
	Common Collective Trust - Cash and Cash Equivalents	—				4,013				—				4,013
	Common Collective Trust - Equity	—				81,636				—				81,636
	Common Collective Trust - Fixed Income	—				174,726				—				174,726
	Common Collective Trust - Real Estate	—				3,864				9,719				13,583
	Hedge Funds	—				—				25,034				25,034
	Total investments measured at fair value	$	—			$	264,780			$	34,753			$	299,533
	Defined Benefit Pension Plans	31-Dec-13
		Level 1				Level 2				Level 3				Total
	AXA Equitable General Fixed Income	$	—			$	1,056			$	—			$	1,056
	Common Collective Trust - Cash and Cash Equivalents	—				1,253				—				1,253
	Common Collective Trust - Equity	—				73,726				—				73,726
	Common Collective Trust - Fixed Income	—				162,747				—				162,747
	Common Collective Trust - Real Estate	—				3,392				8,541				11,933
	Hedge Funds	—				—				29,647				29,647
	Total investments measured at fair value	$	—			$	242,174			$	38,188			$	280,362
	Non-pension Defined Benefit Postretirement Healthcare Plans	31-Dec-14
		Level 1				Level 2				Level 3				Total
	Registered Investment Company Trust - Money Market Mutual Fund	$	—			$	4,705			$	—			$	4,705
	Total investments measured at fair value	$	—			4,705				$	—			$	4,705
	Non-pension Defined Benefit Postretirement Healthcare Plans	31-Dec-13
	Level 1				Level 2				Level 3				Total
Registered Investment Company Trust - Money Market Mutual Fund	$	—			$	4,546			$	—			$	4,546
Total investments measured at fair value	$	—			$	4,546			$	—			$	4,546
The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):
	2014			2013
Balance, beginning of period	$	38,188		$	7,770
Purchase	454			29,000
Unrealized gain (loss)	1,789			1,508
Realized gain (loss)	322			(77		)
Settlements	(6,000		)	(13		)
Balance, end of period	$	34,753		$	38,188
The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):
	Fair Value at			Valuation	Level 3	Range (Weighted)
	31-Dec-14			Technique	Input	Average
Assets:
Common Collective Trust - Real Estate (a)	$	9,719		Market Approach	Redemption Restriction	N/A
Hedge Funds (b)	$	25,034		Market Approach	Redemption Restriction	N/A
_____________
(a)	The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.
(b)	The fair value of the Hedge Funds is determined based on pricing provided or reviewed by the third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.
Additional information about assets of the Pension Plans, including methods and assumptions used to estimate the fair value of these assets, is as follows:
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.
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. Certain of the funds’ assets contain participant withdrawal policy and, therefore, are categorized as Level 3. The funds without participant withdrawal limitations are categorized as Level 2.
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. The Plan’s investment in the hedge fund is categorized as Level 3.
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 accumulated other comprehensive income (in thousands):
Benefit Obligations
		Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans							Non-pension Defined Benefit Postretirement Plans
		2014			2013			2014			2013				2014			2013
Change in benefit obligation:
Projected benefit obligation at beginning of year		$	321,400		363,235			$	32,960		$	34,393			$	45,778		$	46,681
Service cost		5,448			6,433			2,543			1,392				1,700			1,674
Interest cost		15,852			15,300			1,447			1,328				1,919			1,669
Actuarial (gain) loss	(a)	55,384			(38,252		)	5,814			(2,808		)		2,275			(3,379		)
Amendments (b)		—			—			—			—				—			1,585
Benefits paid	(c)	(20,312		)	(25,316		)	(1,553		)	(1,345		)		(3,163		)	(5,123		)
Medicare Part D accrued		—			—			—			—				(99		)	470
Plan participants’ contributions		—			—			—			—				632			2,201
Projected benefit obligation at end of year		$	377,772		$	321,400		$	41,211		$	32,960			$	49,042		$	45,778
____________________
(a)	Change from 2013 reflects a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
(b)	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.
(c) Benefits paid include payments made to terminated vested employees who elected lump-sum offerings of $6.1 million in 2014 and $13 million in 2013.
A reconciliation of the fair value of Plan assets was as follows (in thousands):
	Defined Benefit Pension Plans								Supplemental Non-qualified Defined Benefit Retirement Plans							Non-pension Defined Benefit Postretirement Plans (a)
	2014			2013					2014			2013				2014			2013
Beginning market value of plan assets	$	280,362		$	268,816				$	—		$	—			$	4,546		$	4,351
Investment income (loss)	29,283			24,362					—			—				(43		)	8
Employer contributions	10,200			12,500					—			—				2,733			1,923
Retiree contributions	—			—					—			—				632			1,533
Benefits paid	(20,312		)	(25,316		)	(b)		—			—				(3,163		)	(3,269		)
Plan administrative expenses	—			—					—			—				—			—
Ending market value of plan assets	$	299,533		$	280,362				$	—		$	—			$	4,705		$	4,546
____________________
(a)	Assets of VEBA.
(b)	Benefits paid include payments made to terminated vested employees who elected a lump-sum offering of $6.1 million in 2014 and $13 million in 2013.
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
	2014			2013				2014			2013				2014			2013
Regulatory assets	$	78,864		$	48,419			$	—		$	—			$	7,137		$	5,535
Current liabilities	$	—		$	—			$	1,486		$	1,491			$	3,273		$	2,802
Non-current liabilities	$	78,239		$	41,034			$	39,725		$	32,033			$	41,002		$	38,412
Regulatory liabilities	$	—		$	—			$	—		$	—			$	2,983		$	3,141
Accumulated Benefit Obligation
(in thousands)	Defined Benefit Pension Plans							Supplemental Non-qualified Defined Benefit Plans							Non-pension Defined Benefit Postretirement Healthcare Plans
	2014			2013				2014			2013				2014			2013
Accumulated benefit obligation - Black Hills Corporation	$	135,582		$	110,847			$	29,843		$	27,380			$	12,809		$	12,101
Accumulated benefit obligation - Black Hills Energy	213,398			182,295				386			513				25,456			25,467
Accumulated benefit obligation - Cheyenne Light	—			—				—			—				10,777			8,210
Total Accumulated Benefit Obligation	$	348,980		$	293,142			$	30,229		$	27,893			$	49,042		$	45,778
Components of Net Periodic Expense
(in thousands)	Defined Benefit Pension Plans										Supplemental Non-qualified Defined Benefit Plans										Non-pension Defined Benefit Postretirement Healthcare Plans
	2014			2013			2012				2014			2013			2012				2014			2013			2012
Service cost	$	5,448		$	6,433		$	5,720			$	1,498		$	1,392		$	889			$	1,700		$	1,674		$	1,610
Interest cost	15,852			15,300			14,747				1,447			1,328			1,410				1,919			1,669			2,093
Expected return on assets	(18,065		)	(18,615		)	(16,334		)		—			—			—				(85		)	(79		)	(78		)
Amortization of prior service cost	62			63			89				2			2			3				(428		)	(500		)	(500		)
Recognized net actuarial loss (gain)	4,806			12,250			9,630				498			793			807				160			482			887
Net periodic expense	$	8,103		$	15,431		$	13,852			$	3,445		$	3,515		$	3,109			$	3,266		$	3,246		$	4,012
Accumulated Other Comprehensive Income
In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), 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
	2014			2013				2014			2013				2014			2013
Net (gain) loss	$	10,996		$	4,842			$	8,396		$	4,939			$	1,904		$	1,648
Prior service cost (gain)	51			64				8			9				(1,218		)	(1,213		)
Total accumulated other comprehensive (income) loss	$	11,047		$	4,906			$	8,404		$	4,948			$	686		$	435
The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2015 are as follows (in thousands):
	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	7,174			$	703			$	295
Prior service cost (credit)	38				1				(278		)
Total net periodic benefit cost expected to be recognized during calendar year 2015	$	7,212			$	704			$	17
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:	2014		2013		2012			2014		2013		2012			2014		2013		2012
Discount rate	4.2	%	5.05	%	4.3	%		3.64	%	4.21	%	3.44	%		3.92	%	4.62	%	3.85	%
Rate of increase in compensation levels	3.78	%	3.78	%	3.84	%		5	%	5	%	5	%		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:	2014		2013		2012			2014		2013		2012			2014		2013		2012
Discount rate:
Black Hills Corporation	5.1	%	4.35	%	4.68	%		4.68	%	3.88	%	4.7	%		4.45	%	3.65	%	4.35	%
Black Hills Energy	5	%	4.25	%	4.6	%		3.75	%	3	%	3.9	%		4.25	%	3.5	%	4.35	%
Cheyenne Light	N/A		N/A		N/A			N/A		N/A		N/A			5.15	%	4.4	%	4.65	%
Expected long-term rate of return on assets (a)	6.75	%	7.25	%	7.25	%		N/A		N/A		N/A			2	%	2	%	2	%
Rate of increase in compensation levels	3.78	%	3.78	%	3.75	%		5	%	5	%	5	%		N/A		N/A		N/A
_____________________________
(a)	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.
The healthcare benefit obligation was determined at December 31 as follows:
	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2014
Healthcare trend rate pre-65
Trend for next year	7.5	%	7.5	%	7.5	%
Ultimate trend rate	4.5	%	4.5	%	4.5	%
Year Ultimate Trend Reached	2027		2027		2027
Healthcare trend rate post-65
Trend for next year	6.25	%	6.25	%	6.25	%
Ultimate trend rate	4.5	%	4.5	%	4.5	%
Year Ultimate Trend Reached	2024		2024		2024
2013
Healthcare trend rate pre-65
Trend for next year	7.5	%	7.5	%	7.5	%
Ultimate trend rate	4.5	%	4.5	%	4.5	%
Year Ultimate Trend Reached	2027		2027		2027
Healthcare trend rate post-65
Trend for next year	6.25	%	6.25	%	6.25	%
Ultimate trend rate	4.5	%	4.5	%	4.5	%
Year Ultimate Trend Reached	2026		2026		2026
We do not pre-fund our non-qualified pension plans or two of the three postretirement benefit plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):
Change in Assumed Trend Rate		Impact on December 31, 2014 Accumulated Postretirement				Impact on 2014 Service
		Benefit Obligation				and Interest Cost
Increase 1%		$	2,635			$	168
Decrease 1%		$	(2,166	)		$	(136	)
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plan				Non-Pension Defined Benefit Postretirement Healthcare Plans
2015	$	14,712			$	1,486			$	3,921
2016	$	15,629			$	1,573			$	4,011
2017	$	16,561			$	1,627			$	4,057
2018	$	17,556			$	1,670			$	4,169
2019	$	18,741			$	1,780			$	4,236
2020-2024	$	109,147			$	8,901			$	19,877

Commitments_And_Contingencies

Commitments And Contingencies:	12 Months Ended
	Dec. 31, 2014
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.
	•	Black Hills Power’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.
	•	Black Hills Power 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.
	•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50% of the facility output to Black Hills Power.
	•	Cheyenne Light’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, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.
	•	Colorado Electric’s PPA with Cargill expiring on December 31, 2015, which provides for the purchase of 50 MW energy during heavy load timing intervals.
	•	Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW energy during light load timing intervals.
	•	Colorado Electric’s REPA with AltaGas expiring October 16, 2037, provides up to 14.5 MW of wind energy from the Busch Ranch Wind Project 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):
		2014		2013		2012
	PPA with PacifiCorp	$	13,943	$	13,026	$	13,224
	Transmission services agreement with PacifiCorp	$	1,227	$	1,384	$	1,215
	PPA with Happy Jack	$	3,919	$	3,772	$	1,988
	PPA with Silver Sage	$	4,798	$	4,809	$	3,269
	Busch Ranch Wind Project	$	1,998	$	1,856	$	502
	PPAs with Cargill (a)	$	9,286	$	12,291	$	14,236
	____________________
	(a)    The 2013 and 2012 PPAs were one year contracts replaced by subsequent one year contracts upon expiration.
	Other Gas Supply Agreements
	Our Utilities also purchase natural gas, including transportation capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2017.
	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 ten-year agreement expiring in 2024 became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes.
	Future Minimum Payments
	The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements and natural gas delivery commitments (in thousands):
	2015	$	183,116
	2016	$	131,716
	2017	$	121,867
	2018	$	69,000
	2019	$	35,905
	Thereafter	$	153,395
	Future Purchase Agreement - Related Party
	Cheyenne Light’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 Cheyenne Light 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.
	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.
	•	Black Hills Power 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, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves.
	•	Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.
	•	Black Hills Power 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.
	Purchase Commitment
	On October 14, 2014, we announced an agreement to acquire Energy West Wyoming, Inc., a Wyoming gas utility, and pipeline assets of Gas Natural, Inc. for $17 million. The gas utility serves approximately 6,700 customers, including service to Cody, Ralston and Meeteetse, Wyoming. The pipeline assets include a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory. This purchase is expected to be completed in 2015.
	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 Cheyenne Light 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 Cheyenne Light’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, NOx, mercury 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 2044.
	The EPA issued the Industrial and Commercial Boiler Regulations for Area Sources of Hazardous Air Pollutants, with updates which impose 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.
	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.
	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 $3.9 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 7 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 $1.3 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 is a potential for additional minimal remediation work at Plattsmouth where monitoring is required until 2015. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period, ending in 2015.
As of December 31, 2014, our estimated liabilities for all of the MGP sites currently range from approximately $2.7 million to $6.3 million for which we had $2.7 million accrued for remediation of sites as of December 31, 2014 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.
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.
Oil Creek Fire
On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A fire investigator retained by the Weston County Fire Protection District concluded that the fire was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power. On April 16, 2013, a large group of private landowners filed suit in the United States District Court for the District of Wyoming. There are approximately 36 Plaintiff groups (including property jointly owned by multiple family members or entities), or approximately 73 individually named private plaintiffs. In addition, the State of Wyoming has intervened in the lawsuit. Both the private landowners and the State of Wyoming assert claims for damages against Black Hills Power. The claims include allegations of negligence, negligence per se, common law nuisance and trespass. In addition to claims for compensatory damages, the lawsuit seeks recovery of punitive damages. We have denied and will vigorously defend all claims arising out of the fire. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.
Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. We expect this coverage to limit our exposure and we will pursue recoveries to the maximum extent available under the policies. The deductible applicable to some types of claims arising out of this fire is $1.0 million. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of September 30, 2014, we recorded a loss contingency liability related to these claims and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.
Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. We cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these claimants and other parties. We have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $55 million. We are not yet able to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

Guarantees

Guarantees:	12 Months Ended
	Dec. 31, 2014
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.
	We had the following guarantees in place as of (in thousands):
		Maximum Exposure at
	Nature of Guarantee	31-Dec-14		Expiration
	Indemnification for subsidiary reclamation/surety bonds (a)	$	63,900	Ongoing
	_______________________
	(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.
	During the second quarter of 2014, guarantees of Black Hills Utility Holdings’ payment obligations up to $70 million arising from commodity transactions for natural gas supply were removed, primarily due to improvement of the corporate credit rating, as well as the conversion of certain guarantees to letters of credit.

Oil_and_Gas_Reserves_Unaudited

Oil and Gas Reserves (Unaudited):	12 Months Ended
	Dec. 31, 2014
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 1,205 gross developed oil and gas wells in 10 states and holds leases on approximately 240,816 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):
		2014			2013			2012
	Acquisition of properties:
	Proved	$	4,881		$	234		$	2,437
	Unproved	5,056			6,022			33,052
	Exploration costs	54,355			12,817			115
	Development costs	52,262			48,641			73,877
	Asset retirement obligations incurred	68			143			158
	Total costs incurred	$	116,622		$	67,857		$	109,639
	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, 2014, 2013 and 2012 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.
		2014										2013						2012
		Oil			Gas			NGL				Oil			Gas			Oil			Gas
		(in Mbbls of oil and NGL, and MMcf of gas)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	3,921			63,190			—				4,116			55,985			6,223			95,904
	Production (a)	(337		)	(7,156		)	(135		)		(336		)	(6,984		)	(560		)	(8,686		)
	Additions - acquisitions (sales) (b)	(40		)	(61		)	—				(30		)	(46		)	(2,025		)	(3,070		)
	Additions - extensions and discoveries	733			11,003			182				379			10,456			449			2,898
	Revisions to previous estimates	(1		)	(1,536		)	1,673				(208		)	3,779			29			(31,061		)
	Balance at end of year	4,276			65,440			1,720				3,921			63,190			4,116			55,985
	Proved developed reserves at end of year included above	3,780			57,427			1,530				3,689			60,224			3,929			55,708
	Proved undeveloped reserves at the end of year included in above	496			8,013			191				232			2,966			187			279
	NYMEX prices	$	94.99		$	4.35		$	—		(c)	$	96.94		$	3.67		$	94.71		$	2.76
	Well-head reserve prices	$	85.8		$	3.33		$	34.81			$	89.79		$	3.45		$	85.31		$	2.24
	________________________
	(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.
	(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.
	(c)	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, iso butane, 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.
	Reserve additions totaled 16.5 Bcfe, replacing 165% of annual production. Reserve additions resulted from drilling in the Piceance, Powder River and Williston Basins. Drilling in the Piceance for Mancos Shale accounted for 12.3 Bcfe, Williston Basin (Bakken Shale) accounted for 0.5 Bcfe and Powder River Basin drilling accounted for 3.7 Bcfe. Capital spending in 2014 was primarily for evaluation drilling in the Piceance for Mancos Shale and development drilling in the Williston Bakken Shale play. Exploratory drilling investments were made to develop oil opportunities. Future capital spending rates are anticipated to be dependent on product prices and success in other future drilling.
	In 2014, we had positive revisions of 8.5 Bcfe to previous reserve estimates. Most of the positive revision was the result of reporting natural gas liquids (NGL) in reserves (4.0 Bcfe) and higher equivalent prices of liquids and gas received at the wellhead (2.9 Bcfe). Natural gas in 2013 and prior years was reported wet. We changed our process in 2014 to separate NGL from the wet gas stream, which resulted in an estimated equivalent volume change of 4.0 Bcfe. Most of this change from increased NGL recovery is from the Powder River Finn Field and the Piceance wells. The industry standard multiplication of liquid production by 6 to arrive at the equivalent gas volume results in higher overall equivalent volumes. This is offset by negative revisions of dry natural gas resulting from higher shrink factors during processing of the wet gas to dry gas and NGLs. We will continue to report oil, natural gas and NGL volumes in the future.
	Better wellhead performance resulted in an addition of 2.7 Bcfe, most of which was in the Powder River Basin Finn field and from our 2013 Piceance wells. Higher operating costs caused a minor negative revision of 0.1 Bcfe to 2014 year-end reserves. One proved-undeveloped location in the San Juan Basin was dropped (0.9 Bcfe) because of economics. We sold approximately 0.3 Bcfe of Williston Bakken properties in 2014.
	SEC regulations require that proved undeveloped (PUD) locations meet the test of being developed within five years of being categorized as proved. In 2014, 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.
	•	In 2013, we had 23 gross PUD locations for 4.7 Bcfe; all of the locations were in the Williston, Piceance and San Juan Basins. In 2014, seven locations in the Williston Bakken Shale were drilled and we invested $3.9 million and developed 0.6 Bcfe. One PUD in the San Juan Basin was dropped for economic reasons. Two PUD locations in the Williston Bakken were sold in 2014.
	•	Thirteen gross PUD locations remain undrilled as of December 31, 2014. The remaining 2013 PUD locations require approximately $10.5 million of future investment, and when drilled will develop approximately 3.2 Bcfe. Twelve locations are in the Williston Bakken and one location is in the Piceance Basin.
	•	In 2014, we added 21 gross PUD locations for future Williston Bakken, Piceance Mancos and Powder River Basin drilling.
	•	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, 2014 were:
		Proved Reserves (in Bcfe)		Gross PUD Locations		Future Development Costs (in millions)
	Existing 2013:
	Williston	1.8		21		$	8.6
	Piceance	2.3		1		$	6.4
	San Juan	0.6		1		$	0.9
	Year End Total 2013	4.7		23		$	15.9
	Dropped 2013:
	San Juan	(0.6	)	(1	)	$	(0.9	)
	Drilled in 2014:
	Williston	(0.6	)	(7	)	$	(3.9	)
	Sold:
	Williston	(0.3	)	(2	)	$	(0.7	)
	Added in 2014:
	Williston	0.2		18		$	1
	Powder River	2		1		$	13
	Piceance	6.7		2		$	17.5
		8.9		21		$	31.5
	Total Proved Undeveloped	12.1		34		$	41.9
	•	None of our PUD locations have been reflected in our reserves for five or more years. Consistent with SEC guidance, these PUD locations will be monitored and reported each year until either drilled or revised.
	Capitalized Costs
	Following is information concerning capitalized costs for the years ended December 31 (in thousands):
		2014			2013			2012
Unproved oil and gas properties	$	75,329		$	62,553		$	59,526
Proved oil and gas properties	807,518			725,345			662,444
Gross capitalized costs	882,847			787,898			721,970
Accumulated depreciation, depletion and amortization and valuation allowances (a)	(578,108		)	(555,263		)	(534,777		)
Net capitalized costs	$	304,739		$	232,635		$	187,193
__________________
(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.
Results of Operations
Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
	2014			2013			2012
Revenue	$	55,114		$	54,884		$	79,072
Production costs	22,155			20,140			23,483
Gain on sale of assets	—			—			(29,129		)
Depreciation, depletion and amortization and valuation provisions	26,626			20,611			37,323
Impairment of long-lived assets	—			—			26,868
Total costs	48,781			40,751			58,545
Results of operations from producing activities before tax	6,333			14,133			20,527
Income tax benefit (expense)	(2,185		)	(4,876		)	(7,082		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	4,148		$	9,257		$	13,445
Unproved Properties
Unproved properties not subject to amortization at December 31, 2014, 2013 and 2012 consisted mainly of exploration cost 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 $1.0 million, $1.1 million and $0.7 million of interest during 2014, 2013 and 2012, 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. We expect the exploration cost listed below to be added to the cost pool in the next year.
The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and notes the year in which the associated costs were incurred (in thousands):
	2014			2013			2012			Prior			Total
Leasehold acquisition cost	$	16,077		$	4,889		$	35,823		$	13,412		$	70,201
Exploration cost	23,954			10,212			—			—			34,166
Capitalized interest	207			748			360			3,813			5,128
Total	$	40,238		$	15,849		$	36,183		$	17,225		$	109,495
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):
	2014			2013			2012
Future cash inflows	$	675,973		$	602,501		$	502,769
Future production costs	(245,180		)	(213,578		)	(186,695		)
Future development costs, including plugging and abandonment	(45,123		)	(40,557		)	(8,462		)
Future income tax expense	(29,523		)	(81,566		)	(69,877		)
Future net cash flows	356,147			266,800			237,735
10% annual discount for estimated timing of cash flows	(173,125		)	(107,375		)	(101,632		)
Standardized measure of discounted future net cash flows	$	183,022		$	159,425		$	136,103
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):
	2014			2013			2012
Standardized measure - beginning of year	$	159,425		$	136,103		$	203,357
Sales and transfers of oil and gas produced, net of production costs	(32,139		)	(35,932		)	(48,905		)
Net changes in prices and production costs	(28,544		)	15,126			(42,639		)
Extensions, discoveries and improved recovery, less related costs	17,582			29,574			19,870
Changes in future development costs	3,195			(12,216		)	43,854
Development costs incurred during the period	2,079			3,554			21,931
Revisions of previous quantity estimates	23,722			12,851			(86,277		)
Accretion of discount	18,437			15,126			25,509
Net change in income taxes	19,265			(3,892		)	36,578
Purchases of reserves	—			—			—
Sales of reserves (a)	—			(869		)	(37,175		)
Standardized measure - end of year	$	183,022		$	159,425		$	136,103
________
(a)	Reflects sale of Williston Basin assets in 2012.
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.

Sale_Of_Operating_Assets_and_D

Sale Of Operating Assets and Discontinued Operations:	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Sale of Operating Assets and Discontinued Operations	SALE OF OPERATING ASSETS AND DISCONTINUED OPERATIONS
	Partial Sale of Electric Utilities Assets
	On September 18, 2012, Colorado Electric completed the sale of an undivided 50% ownership interest in the Busch Ranch Wind project for $25 million. Colorado Electric retains the remaining undivided interest and is the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm commenced on October 16, 2012. Colorado Electric will purchase our partner’s interest in the energy produced by the wind farm through a REPA. See Note 18 for further information.
	Partial Sale of Oil and Gas Assets
	On September 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin in North Dakota. An effective date of July 1, 2012, was used to determine the sales price.
	Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically, this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Williston Basin asset sale significantly altered the relationship and accordingly we recorded a gain of $29 million with the remainder of the proceeds recorded as a reduction in the full cost pool. As a result of the reduction in the full cost pool from the sale of these assets, the depreciation, depletion and amortization rate declined during 2013.
	Net cash proceeds, subsequent to the true-up of all post-closing adjustments, were as follows (in thousands):
	Cash proceeds received on date of sale	$	243,314
	Adjusted for:
	Post close adjustments	2,793
	Transaction adviser fees	(1,400		)
	Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
	Net cash proceeds	$	227,860
	_____________
	*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.
	Discontinued Operations
	Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income and Consolidated Statements of Cash Flows. For comparative purposes, all prior periods presented have been restated to reflect the reclassification on a consistent basis.
	Energy Marketing Segment
	On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds at date of sale were approximately $165 million, subject to final post-closing adjustments. Those proceeds represented $108 million received from the buyer and $58 million of cash retained from Enserco before closing.
	The buyer asserted certain purchase price adjustments, some that we accepted, and several that we disputed. The disputed claims were resolved through a binding arbitration decision dated January 17, 2014. We expensed $1.4 million in 2012, relative to purchase price adjustments we accepted through a partial settlement agreement with the buyer, and an additional $1.1 million in 2013 relative to the claims assigned to arbitration. Loss from discontinued operations was $0.9 million for the twelve months ended December 31, 2013. Results for 2013 include the settlement of unresolved purchase price adjustments.
	Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):
	For the Years Ended December 31,	2013			2012
	Revenue	$	—		$	(604	)
	Pre-tax income (loss) from discontinued operations	—			(6,061		)
	Pre-tax gain (loss) on sale	(1,391		)	(4,184		)
	Income tax (expense) benefit	507			3,268
	Income (loss) from discontinued operations, net of tax (a)	$	(884	)	$	(6,977	)
	________
	(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended December 31, 2012.
	Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment.

Quarterly_Historical_Data_Unau

Quarterly Historical Data (Unaudited):	12 Months Ended
	Dec. 31, 2014
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 2014 and 2013.
		First Quarter		Second Quarter		Third		Fourth Quarter
						Quarter
		(in thousands, except per share amounts, dividends and common stock prices)
	2014
	Revenue	$	460,169	$	283,237	$	272,087	$	378,077
	Operating income	$	89,598	$	46,577	$	54,404	$	69,951
	Income (loss) from continuing operations	$	48,118	$	19,820	$	26,836	$	34,007
	Net income (loss) available for common stock	$	48,118	$	19,820	$	26,836	$	34,007
	Income (loss) per share - Basic	$	1.09	$	0.45	$	0.6	$	0.77
	Income (loss) per share - Diluted	$	1.08	$	0.44	$	0.6	$	0.76
	Dividends paid per share	$	0.39	$	0.39	$	0.39	$	0.39
	Common stock prices - High	$	59.05	$	61.41	$	62.13	$	57.17
	Common stock prices - Low	$	51.09	$	55.23	$	47.87	$	47.11
		First Quarter		Second Quarter		Third		Fourth
						Quarter		Quarter
		(in thousands, except per share amounts, dividends and common stock prices)
	2013
	Revenue	$	380,671	$	279,826	$	259,907	$	355,448
	Operating income	$	79,846	$	49,037	$	55,566	$	71,103
	Income (loss) from continuing operations (a) (b)	$	43,197	$	30,518	$	23,124	$	19,007
	Income (loss) from discontinued operations	$	—	$	—	$	—	$	(884	)
	Net income (loss) available for common stock (a) (b)	$	43,197	$	30,518	$	23,124	$	18,123
	Income (loss) per share for continuing operations - Basic	$	0.98	$	0.69	$	0.52	$	0.43
	Income (loss) per share for discontinued operations - Basic	—		—		—		(0.02		)
	Income (loss) per share - Basic	$	0.98	$	0.69	$	0.52	$	0.41
	Income (loss) per share for continuing operations - Diluted	$	0.97	$	0.69	$	0.52	$	0.43
	Income (loss) per share for discontinued operations - Diluted	—		—		—		(0.02		)
	Income (loss) per share - Diluted	$	0.97	$	0.69	$	0.52	$	0.41
	Dividends paid per share	$	0.38	$	0.38	$	0.38	$	0.38
	Common stock prices - High	$	44.32	$	50.53	$	55.09	$	54.83
	Common stock prices - Low	$	36.89	$	43.19	$	46.62	$	47
	__________________________
	(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
	(b)	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.

Schedule_II_Consolidated_Valua

Schedule II Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
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, 2014, 2013 AND 2012
	Description	Balance at Beginning of Year		Adjustments		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:
	2014	$	1,237	$	—	$	4,470	$	4,233	$	(8,424	)	$	1,516
	2013	$	768	$	—	$	2,780	$	4,999	$	(7,310	)	$	1,237
	2012	$	1,661	$	—	$	1,913	$	3,822	$	(6,628	)	$	768

Business_Description_And_Signi1

Business Description And Significant Accounting Policies: Business Description (Policies)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business Description	Business Description
	Black Hills Corporation is a diversified energy company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, operates in two primary business groups: Utilities and Non-regulated Energy.
	The Utilities Group includes our Electric Utilities and Gas Utilities segments. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric and the electric and natural gas utility operations of Cheyenne Light, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyoming and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas and Kansas Gas.
	The Non-regulated Energy Group includes our Power Generation, Coal Mining and Oil and Gas segments. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. Oil and Gas, 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. These businesses are aggregated for reporting purposes as Non-regulated Energy.
	On February 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being reclassified as discontinued operations. See Note 21 for additional information.
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 4.
	Our Consolidated Statements of Income 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 3 for additional information.
	As a result of the sale of our Energy Marketing segment, amounts associated with this segment have been reclassified as discontinued operations on the accompanying Consolidated Financial Statements. See Note 21 for additional information.
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 Utilities Group 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 unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group 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 against amounts due 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 tax 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.
	The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus cost of removal, 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, a unit-of-production methodology based on plant hours run is used.
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. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 21 for further discussion.
	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 a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2014 or 2013. See Note 12 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 elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 20.
	Companies are permitted but not required to disclose probable and possible reserves. We have elected not to report on 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 this annual review of goodwill and indefinite lived intangible assets as of November 30 each year (or more frequently if impairment indicators arise).
	We performed our annual goodwill impairment tests as of November 30, 2014. 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.
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. 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, and 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 regulated electric and gas 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.
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 Utilities Group follows accounting standards for regulated operations and reflects 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. 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 liability method in accounting for income taxes. Under the 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. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities.
	It is our policy to apply the flow-through method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. 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. Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property.
	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.
	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 outstanding stock options, restricted stock and performance shares under our equity compensation plans.
Discontinued Operations	Discontinued Operations
	On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. In accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. See Note 21 for additional information.
Recently Issued and Adopted Accounting Standards	Recently Issued and Adopted Accounting Standards
	We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.
	Revenue from Contracts with Customers, ASU 2014-09
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.
	Recently Issued Accounting Pronouncements and Legislation
	Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforwards Exists, ASU 2013-11
	In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after December 15, 2013 and interim periods within those years, and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard did not have any impact on our financial position, results of operations or cash flows.
	Final Tangible Property Regulations, Treasury Decision 9636
	In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts paid to acquire, produce, or improve tangible property. The regulations had the effect of a change in law and as a result, the impact should be taken into account in the period of adoption. In general, such regulations apply to tax years beginning on or after January 1, 2014, with early adoption permitted. We implemented all of the provisions of the final regulations with the filing of the 2013 federal income tax return in September 2014. The adoption of the final regulations did not have a material impact on our consolidated financial statements.

Business_Description_And_Signi2

Business Description And Significant Accounting Policies: Business Description (Tables)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of accounts receivable as of December 31 (in thousands):
	2014	Accounts Receivable, Trade			Unbilled Revenue			Less Allowance for Doubtful Accounts			Accounts Receivable, net
	Electric Utilities	$	59,714		$	26,474		$	(722	)	$	85,466
	Gas Utilities	47,394			45,546			(781		)	92,159
	Power Generation	1,369			—			—			1,369
	Coal Mining	3,151			—			—			3,151
	Oil and Gas	5,305			—			(13		)	5,292
	Corporate	2,555			—			—			2,555
	Total	$	119,488		$	72,020		$	(1,516	)	$	189,992
	2013	Accounts Receivable, Trade			Unbilled Revenue			Less Allowance for Doubtful Accounts			Accounts Receivable, net
	Electric Utilities	$	52,437		$	23,823		$	(666	)	$	75,594
	Gas Utilities	49,162			41,195			(558		)	89,799
	Power Generation	1,722			—			—			1,722
	Coal Mining	1,711			—			—			1,711
	Oil and Gas	8,156			—			(13		)	8,143
	Corporate	604			—			—			604
	Total	$	113,792		$	65,018		$	(1,237	)	$	177,573
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):
		31-Dec-14			31-Dec-13
	Materials and supplies	$	49,555		$	50,196
	Fuel - Electric Utilities	6,637			6,213
	Natural gas in storage held for distribution	34,999			32,069
	Total materials, supplies and fuel	$	91,191		$	88,478
Goodwill	Goodwill balances were as follows (in thousands):
		Electric Utilities			Gas Utilities			Power Generation			Total
	Ending balance at December 31, 2012	$	250,487		$	94,144		$	8,765		$	353,396
	Additions (adjustments)	—			—			—			—
	Ending balance at December 31, 2013	$	250,487		$	94,144		$	8,765		$	353,396
	Additions (adjustments)	—			—			—			—
	Ending balance at December 31, 2014	$	250,487		$	94,144		$	8,765		$	353,396
Intangible Assets	Changes to intangible assets for the years ended December 31, were as follows (in thousands):
		2014			2013			2012
	Intangible assets, net, beginning balance	$	3,397		$	3,620		$	3,843
	Additions (adjustments)	—			—			—
	Amortization expense*	(221		)	(223		)	(223		)
	Intangible assets, net, ending balance	$	3,176		$	3,397		$	3,620
	_________________
	*	Amortization expense for existing intangible assets is expected to be $0.2 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)	31-Dec-14			31-Dec-13
	Regulatory assets
	Deferred energy and fuel cost adjustments - current (a)(d)	1	$	23,820		$	16,775
	Deferred gas cost adjustments (a)(d)	2	37,471			4,799
	Gas price derivatives (a)	7	18,740			7,567
	AFUDC (b)	45	12,358			12,315
	Employee benefit plans (c) (e)	12	97,126			67,059
	Environmental (a)	subject to approval	1,314			1,800
	Asset retirement obligations (a)	44	3,287			3,266
	Bond issue cost (a)	23	3,276			3,419
	Renewable energy standard adjustment (a)	5	9,622			14,186
	Flow through accounting (c)	35	25,887			20,916
	Decommissioning costs	10	12,484			—
	Other regulatory assets (a)	15	12,454			10,546
			$	257,839		$	162,648
	Regulatory liabilities
	Deferred energy and gas costs (a)	1	$	6,496		$	11,708
	Employee benefit plans (c) (e)	12	53,139			34,431
	Cost of removal (a)	44	78,249			64,970
	Other regulatory liabilities (c)	25	10,947			9,047
			$	148,831		$	120,156
	__________
	(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. Increases in the current year balances as of December 31, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. 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)	Increases are due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):
		31-Dec-14			31-Dec-13			31-Dec-12
	Income (loss) from continuing operations	$	128,781		$	115,846		$	88,505
	Weighted average shares - basic	44,394			44,163			43,820
	Dilutive effect of:
	Equity compensation	204			256			250
	Other	—			—			3
	Weighted average shares - diluted	44,598			44,419			44,073
	Income (loss) from continuing operations, per share - Diluted	$	2.89		$	2.61		$	2.01
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):
		31-Dec-14		31-Dec-13		31-Dec-12
	Equity compensation	81		22		163
	Anti-dilutive shares excluded from computation of earnings (loss) per share	81		22		163

Property_Plant_And_Equipment_P

Property, Plant And Equipment: Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
	Utilities Group	2014			2013				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	$	1,125,845	45	$	951,138		45	25	65
	Electric transmission	284,032		49	238,542			50	40	65
	Electric distribution	718,342		44	666,589			44	15	65
	Plant acquisition adjustment (a)	4,870		32	4,870			32	32	32
	General	152,982		21	138,263			22	3	60
	Capital lease - plant in service (b)	261,441		20	261,441			20	20	20
	Total electric plant in service	$	2,547,512		$	2,260,843
	Construction work in progress	49,700			203,760
	Total electric plant	2,597,212			2,464,603
	Less accumulated depreciation and amortization	484,406			472,970
	Electric plant net of accumulated depreciation and amortization	$	2,112,806		$	1,991,633
	_____________
	(a) The plant acquisition adjustment is included in rate base and is being recovered with 16 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.
		2014			2013				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	$	13	37	$	13		37	37	37
	Gas transmission	24,090		54	24,984			54	53	57
	Gas distribution	557,405		46	507,318			46	41	56
	General	90,085		19	85,841			19	16	22
	Total gas plant in service	671,593			618,156
	Construction work in progress	16,072			9,417
	Total gas plant	687,665			627,573
	Less accumulated depreciation and amortization	92,035			84,679
	Gas plant net of accumulated depreciation and amortization	$	595,630		$	542,894
	2014														Lives ( in years)
	Non-regulated Energy	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	$	153,779	$	2,262		$	156,041		$	47,704		$	108,337	33	2	40
	Coal Mining	145,619		3,748			149,367			90,629			58,738		15	2	59
	Oil and Gas	962,395		—			962,395			612,736			349,659		24	3	25
		$	1,261,793	$	6,010		$	1,267,803		$	751,069		$	516,734
	2013														Lives ( in years)
	Non-regulated Energy	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	$	143,026	$	10,491		$	153,517		$	43,069		$	110,448	36	2	40
	Coal Mining	149,067		1,156			150,223			86,306			63,917		14	2	59
	Oil and Gas	852,384		—			852,384			585,334			267,050		24	3	25
		$	1,144,477	$	11,647		$	1,156,124		$	714,709		$	441,415
	2014														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	$	5,524	$	5,196		$	10,720		$	(3,485	)	$	14,205	11	5	30
	___________
	(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
	2013														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	$	5,498	$	5,647		$	11,145		$	(3,210	)	$	14,355	6	2	30
	___________
	(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.

Jointly_Owned_Facilities_Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2014, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
		Plant in Service		Construction Work in Progress		Accumulated Depreciation
	Wyodak Plant	$	110,123	$	1,201	$	53,816
	Transmission Tie	$	19,648	$	—	$	4,976
	Wygen I	$	109,040	$	1,765	$	31,852
	Wygen III	$	136,220	$	29	$	13,811
	Busch Ranch Wind Project	$	18,590	$	—	$	1,573

Business_Segments_Information_

Business Segments Information: Business Segments Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting Information, Additional Information [Abstract]
Segment information included in Condensed Consolidated Balance Sheets	Segment information was as follows (in thousands):
	Total Assets (net of inter-company eliminations) as of December 31,	2014			2013
	Utilities:
	Electric (a)	$	2,748,680		$	2,525,947
	Gas	906,922			805,617
	Non-regulated Energy:
	Power Generation (a)	76,945			95,692
	Coal Mining	74,407			78,825
	Oil and Gas	366,247			288,366
	Corporate	106,605			80,731
	Total assets	$	4,279,806		$	3,875,178
	__________________
	(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.
	Capital Expenditures and Asset Acquisitions(a) for the years ended December 31,	2014			2013
	Utilities:
	Electric Utilities	$	193,199		$	222,262
	Gas Utilities	70,528			63,205
	Non-regulated Energy:
	Power Generation	2,379			13,533
	Coal Mining	6,676			5,528
	Oil and Gas	109,439			64,687
	Corporate	9,046			10,319
	Total capital expenditures and asset acquisitions	$	391,267		$	379,534
	_________________
	(a)	Includes accruals for property, plant and equipment.
	Property, Plant and Equipment as of December 31,	2014			2013
	Utilities:
	Electric Utilities (a)	$	2,597,212		$	2,464,603
	Gas Utilities	687,665			627,573
	Non-regulated Energy:
	Power Generation (a)	156,041			153,517
	Coal Mining	149,367			150,223
	Oil and Gas	962,395			852,384
	Corporate	10,720			11,145
	Total property, plant and equipment	$	4,563,400		$	4,259,445
	_______________
	(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.
Segment information included in Condensed Consolidated Statements of Income
		Consolidating Income Statement
	Year ended December 31, 2014	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
	Revenue	$	683,201		$	617,768		$	6,401		$	31,086		$	55,114		$	—		$	—		$	1,393,570
	Inter-company revenue	14,110			—			81,157			32,272			—			222,460			(349,999		)	—
	Total revenue	697,311			617,768			87,558			63,358			55,114			222,460			(349,999		)	1,393,570
	Fuel, purchased power and cost of natural gas sold	314,573			380,852			—			—			—			116			(113,759		)	581,782
	Operations and maintenance	165,641			132,635			33,126			41,172			42,659			213,415			(225,473		)	403,175
	Depreciation, depletion and amortization	79,424			26,499			4,540			10,276			27,584			7,690			(7,930		)	148,083
	Operating income (loss)	137,673			77,782			49,892			11,910			(15,129		)	1,239			(2,837		)	260,530
	Interest expense	(53,402		)	(15,725		)	(4,351		)	(493		)	(2,603		)	(50,299		)	55,913			(70,960		)
	Interest income	4,615			441			682			59			918			48,969			(53,759		)	1,925
	Other income (expense), net	1,164			34			(6		)	2,275			183			61,605			(62,574		)	2,681
	Income tax benefit (expense)	(30,498		)	(20,663		)	(17,701		)	(3,299		)	5,998			24			744			(65,395		)
	Income (loss) from continuing operations	$	59,552		$	41,869		$	28,516		$	10,452		$	(10,633	)	$	61,538		$	(62,513	)	$	128,781
		Consolidating Income Statement
	Year ended December 31, 2013	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
	Revenue	$	651,445		$	539,689		$	4,648		$	25,186		$	54,884		$	—		$	—		$	1,275,852
	Inter-company revenue	13,863			—			78,389			31,442			—			220,620			(344,314		)	—
	Total revenue	665,308			539,689			83,037			56,628			54,884			220,620			(344,314		)	1,275,852
	Fuel, purchased power and cost of natural gas sold	294,048			310,463			—			—			—			125			(112,489		)	492,147
	Operations and maintenance	159,961			126,073			30,186			39,519			40,365			202,809			(211,977		)	386,936
	Depreciation, depletion and amortization	77,704			26,381			5,091			11,523			21,770			11,624			(12,876		)	141,217
	Operating income (loss)	133,595			76,772			47,760			5,586			(7,251		)	6,062			(6,972		)	255,552
	Interest expense (a)	(61,537		)	(25,234		)	(21,178		)	(641		)	(2,253		)	(85,195		)	84,250			(111,788		)
	Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			30,169			—			30,169
	Interest income	5,277			976			785			10			1,639			69,760			(76,724		)	1,723
	Other income (expense), net	633			(60		)	1			2,304			108			41,453			(42,641		)	1,798
	Income tax benefit (expense)	(25,834		)	(19,747		)	(11,080		)	(932		)	3,545			(7,778		)	218			(61,608		)
	Income (loss) from continuing operations	$	52,134		$	32,707		$	16,288		$	6,327		$	(4,212	)	$	54,471		$	(41,869	)	$	115,846
	________________
	(a)	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).
		Consolidating Income Statement
	Year ended December 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total
	Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
	Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
	Total revenue	626,966			454,081			79,389			57,778			79,072			196,453			(319,855		)	1,173,884
	Fuel, purchased power and cost of natural gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
	Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
	Gain on sale of operating assets (a)	—			—			—			—			(29,129		)	—			—			(29,129		)
	Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
	Impairment of long-lived assets(b)	—			—			—			—			26,868			—			—			26,868
	Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711
	Interest expense(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
	Unrealized gain (loss) on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
	Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
	Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
	Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
	Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505
	________________
	(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
	(b)	Oil and Gas includes a ceiling test impairment (see Note 12).
	(c)	Corporate includes a make-whole provision from early repayment of long-term debt.

LongTerm_Debt_LongTerm_Debt_Ta

Long-Term Debt: Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt outstanding was as follows (dollars in thousands) as of:
			Interest Rate at
		Due Date	31-Dec-14	31-Dec-14			31-Dec-13
	Corporate
	Senior unsecured notes due 2023	30-Nov-23	4.25%	$	525,000		$	525,000
	Unamortized discount on Senior unsecured note due 2023 (a)			(2,164		)	—
	Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
	Corporate term loan due 2015 (b)	June 19, 2015	1.31%	275,000			275,000
	Total Corporate Debt			997,836			1,000,000
	Electric Utilities
	First Mortgage Bonds due 2044	20-Oct-44	4.43%	85,000			—
	First Mortgage Bonds due 2044	20-Oct-44	4.53%	75,000			—
	First Mortgage Bonds due 2032	15-Aug-32	7.23%	75,000			75,000
	First Mortgage Bonds due 2039	1-Nov-39	6.13%	180,000			180,000
	Unamortized discount on First Mortgage Bonds due 2039			(102		)	(107		)
	Pollution control revenue bonds due 2024	1-Oct-24	5.35%	—			12,200
	First Mortgage Bonds due 2037	20-Nov-37	6.67%	110,000			110,000
	Industrial development revenue bonds due 2021, variable rate (c)	1-Sep-21	0.09%	7,000			7,000
	Industrial development revenue bonds due 2027, variable rate (c)	March 1, 2027	0.09%	10,000			10,000
	Series 94A Debt, variable rate (c)	June 1, 2024	0.75%	2,855			2,855
	Total Electric Utilities			544,753			396,948
	Total long-term debt			1,542,589			1,396,948
	Less current maturities			275,000			—
	Long-term debt, net of current maturities			$	1,267,589		$	1,396,948
	_______________
	(a)	Discount on note initially reflected in deferred financing costs at December 31, 2013.
	(b)	Variable interest rate, based on LIBOR plus a spread.
	(c)	Variable interest rate.
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):
	2015	$	275,000
	2016	$	—
	2017	$	—
	2018	$	—
	2019	$	—
	Thereafter	$	1,269,855
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
		Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at				Amortization Expense for the years ended December 31,
		31-Dec-14				2014			2013			2012
	Senior unsecured notes due 2023	$	3,908			$	653		$	86		$	—
	Senior unsecured notes due 2014	$	—			$	—		$	635		$	462
	Senior unsecured notes due 2020	$	926			$	167		$	167		$	167
	First mortgage bonds due 2044 (Black Hills Power) (a)	$	711			$	6		$	—		$	—
	First mortgage bonds due 2044 (Cheyenne Light) (a)	$	654			$	6		$	—		$	—
	First mortgage bonds due 2032	$	584			$	33		$	33		$	33
	First mortgage bonds due 2039	$	1,885			$	76		$	76		$	76
	First mortgage bonds due 2037	$	705			$	31		$	31		$	31
	Black Hills Wyoming project financing due 2016 (b)	$	—			$	—		$	3,177		$	1,037
	Other	$	483			$	53		$	57		$	57
	_____________
	(a)	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.
	(b)	This project financing was repaid in 2013 and the deferred financing costs were written off.
	The deferred financing costs on the new facility are being amortized as follows (in thousands):
		Deferred Financing Costs Remaining on Balance Sheets as of			Amortization Expense for the years ended December 31,
		31-Dec-14			2014			2013			2012
	Revolving Credit Facility	$	1,779		$	616		$	752		$	2,187

Notes_Payable_Notes_Payable_Ta

Notes Payable: Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2014
Notes Payable [Abstract]
Schedule of Short-term Debt	We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):
		Balance Outstanding at
		31-Dec-14		31-Dec-13
	Revolving Credit Facility	$	75,000	$	82,500
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
		Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheets at			Amortization Expense for the years ended December 31,
		31-Dec-14			2014			2013			2012
	Senior unsecured notes due 2023	$	3,908		$	653		$	86		$	—
	Senior unsecured notes due 2014	$	—		$	—		$	635		$	462
	Senior unsecured notes due 2020	$	926		$	167		$	167		$	167
	First mortgage bonds due 2044 (Black Hills Power) (a)	$	711		$	6		$	—		$	—
	First mortgage bonds due 2044 (Cheyenne Light) (a)	$	654		$	6		$	—		$	—
	First mortgage bonds due 2032	$	584		$	33		$	33		$	33
	First mortgage bonds due 2039	$	1,885		$	76		$	76		$	76
	First mortgage bonds due 2037	$	705		$	31		$	31		$	31
	Black Hills Wyoming project financing due 2016 (b)	$	—		$	—		$	3,177		$	1,037
	Other	$	483		$	53		$	57		$	57
	_____________
	(a)	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.
	(b)	This project financing was repaid in 2013 and the deferred financing costs were written off.
	The deferred financing costs on the new facility are being amortized as follows (in thousands):
		Deferred Financing Costs Remaining on Balance Sheets as of		Amortization Expense for the years ended December 31,
		31-Dec-14		2014			2013			2012
	Revolving Credit Facility	$	1,779	$	616		$	752		$	2,187
Schedule of Credit Facility Covenants	Our Revolving Credit Facility and our new Term Loan require compliance with the following financial covenant at the end of each quarter:
		At December 31, 2014		Covenant Requirement
	Recourse leverage ratio	55	%	Less than	65	%

Asset_Retirement_Obligations_A

Asset Retirement Obligations: Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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):
		31-Dec-13		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates (a) (b)			31-Dec-14
	Electric Utilities	$	6,922	$	—	$	(85	)	$	175	$	—		$	7,012
	Gas Utilities	274		—		—			17		—			291
	Coal Mining	20,627		345		—			951		(2,785		)	19,138
	Oil and Gas	24,028		68		(932		)	1,043		(3,262		)	20,945
	Total	$	51,851	$	413	$	(1,017	)	$	2,186	$	(6,047	)	$	47,386
		31-Dec-12		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates			31-Dec-13
	Electric Utilities	$	6,981	$	—	$	—		$	168	$	(227	)	$	6,922
	Gas Utilities	259		—		—			15		—			274
	Coal Mining	20,286		3		(714		)	1,052		—			20,627
	Oil and Gas	23,022		143		(1,903		)	1,450		1,316			24,028
	Total	$	50,548	$	146	$	(2,617	)	$	2,685	$	1,089		$	51,851
	_____________________
	(a)	The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability.
	(b)	The Oil and Gas Revision to Prior Estimates was due to a change in useful well lives used in calculating the estimated liability.

Risk_Management_Activities_Ris

Risk Management Activities: Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		31-Dec-14			31-Dec-13
		Interest Rate Swaps (a)			Interest Rate Swaps (a)
	Notional	$	75,000		$	75,000
	Weighted average fixed interest rate	4.97		%	4.97		%
	Maximum terms in years	2			3
	Derivative liabilities, current	$	3,340		$	3,474
	Derivative liabilities, non-current	$	2,680		$	5,614
	___________________
	(a)	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related borrowings.
Derivative Instruments, Gain (Loss)	The impact of cash flow hedges on our Consolidated Statements of Income (Loss) for years ended were as follows (in thousands):
		31-Dec-14
	Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	(536	)	Interest expense	$	3,669			$	—
	Commodity derivatives	14,681			Revenue	1,995				—
	Total	$	14,145			$	5,664			$	—
		31-Dec-13
	Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	7,935		Interest expense	$	6,989			$	—
	Commodity derivatives	(956		)	Revenue	(927		)		—
	Total	$	6,979			$	6,062			$	—
		31-Dec-12
	Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			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	$	(4,794	)	Interest expense	$	(7,607	)		$	—
	Commodity derivatives	2,639			Revenue	8,784				—
	Total	$	(2,155	)		$	1,177			$	—
	Derivatives Not Designated as Hedge Instruments
	The impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31 were as follows (in thousands):
			2014			2013			2012
	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
	Interest rate swaps - unrealized (a)	Unrealized gain (loss) on interest rate swap, net	$	—		$	30,169		$	1,882
	Interest rate swaps - realized (a)	Interest expense	—			(12,902		)	(12,959		)
			$	—		$	17,267		$	(11,077	)
	_______________
	(a)	These interest rate swaps were settled in the fourth quarter of 2013.
Oil and Gas [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The contract or notional amounts, terms of our commodity derivatives and the derivative balances for our Oil and Gas segment reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of:
		31-Dec-14						31-Dec-13
		Crude oil futures, swaps and options			Natural gas futures, swaps and options			Crude oil futures, swaps and options			Natural gas futures, swaps and options
	Notional (a)	334,500			6,582,500			412,500			7,082,500
	Maximum terms in months (b)	1			1			3			1
	Derivative assets, current	$	—		$	—		$	55		$	—
	Derivative assets, non-current	$	—		$	—		$	—		$	—
	Derivative liabilities, current	$	—		$	—		$	—		$	—
	Derivative liabilities, non-current	$	—		$	—		$	—		$	—
	________________________
	(a)	Crude in Bbls, gas in MMBtu.
	(b)	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
Utilities Group [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	We had the following derivative balances related to the hedges in our Utilities reflected in our Consolidated Balance Sheets as of (in thousands):
		31-Dec-14			31-Dec-13
	Derivative assets, current	$	—		$	662
	Derivative assets, non-current	$	—		$	—
	Derivative liabilities, current	$	—		$	—
	Derivative liabilities, non-current	$	—		$	—
	Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	18,740		$	7,567
Contract or notional amounts and terms of marketing activities and derivative commodity instruments	The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were as follows, as of:
		31-Dec-14			31-Dec-13
		Notional (MMBtus)		Maximum Term (months) (a)	Notional (MMBtus)		Maximum Term (months) (a)
	Natural gas futures purchased	19,370,000		72	17,930,000		84
	Natural gas options purchased	4,020,000		8	3,890,000		8
	Natural gas basis swaps purchased	12,005,000		60	14,785,000		60
	__________
	(a) Term reflects the maximum forward period hedged.

Fair_Value_Measurements_Fair_V

Fair Value Measurements: Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	A discussion of fair value of financial instruments is included in Note 10. 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, 2014
		Level 1			Level 2			Level 3				Cash Collateral and Counterparty Netting			Total
	Assets:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			8,599			—				(8,599		)	—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			6,558			—				(6,558		)	—
	Commodity derivatives - Utilities	—			2,389			—				(2,389		)	—
	Total	$	—		$	17,546		$	—			$	(17,546	)	$	—
	Liabilities:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			—			—				—			—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			473			—				(473		)	—
	Commodity derivatives - Utilities	—			19,303			—				(19,303		)	—
	Interest rate swaps	—			6,020			—				—			6,020
	Total	$	—		$	25,796		$	—			$	(19,776	)	$	6,020
		As of December 31, 2013
		Level 1			Level 2			Level 3				Cash Collateral and Counterparty Netting			Total
	Assets:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			130			—				(75		)	55
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			815			—				(815		)	—
	Commodity derivatives - Utilities	—			3,030			—				(2,368		)	662
	Total	$	—		$	3,975		$	—			$	(3,258	)	$	717
	Liabilities:
	Commodity derivatives - Oil and Gas:
	Options -- Oil	$	—		$	—		$	—			$	—		$	—
	Basis Swaps -- Oil	—			1,229			—				(1,229		)	—
	Options -- Gas	—			—			—				—			—
	Basis Swaps -- Gas	—			531			—				(531		)	—
	Commodity derivatives - Utilities	—			9,100			—				(9,100		)	—
	Interest rate swaps	—			9,088			—				—			9,088
	Total	$	—		$	19,948		$	—			$	(10,860	)	$	9,088
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):
			2014						2013
		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	$	10,391		$	—		$	248		$	—
	Commodity derivatives	Derivative assets - non-current	4,766			—			698			—
	Commodity derivatives	Derivative liabilities - current	—			185			—			1,541
	Commodity derivatives	Derivative liabilities - non-current	—			288			—			219
	Interest rate swaps	Derivative liabilities - current	—			3,340			—			3,474
	Interest rate swaps	Derivative liabilities - non-current	—			2,680			—			5,614
	Total derivatives designated as hedges		$	15,157		$	6,493		$	946		$	10,848
	Derivatives not designated as hedges:
	Commodity derivatives	Derivative assets - current	$	—		$	—		$	662		$	—
	Commodity derivatives	Derivative assets - non-current	—			—			—			—
	Commodity derivatives	Derivative liabilities - current	—			8,032			—			—
	Commodity derivatives	Derivative liabilities - non-current	—			8,882			—			6,732
	Interest rate swaps	Derivative liabilities - current	—			—			—			—
	Interest rate swaps	Derivative liabilities - non-current	—			—			—			—
	Total derivatives not designated as hedges		$	—		$	16,914		$	662		$	6,732
Schedule of Derivative Offsetting on Balance Sheet	Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2014 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 - Crude Basis Swaps	$	8,599		$	(8,599	)	$	—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	6,558			(6,558		)	—
	Utilities	2,389			(2,389		)	—
	Total derivative assets subject to a master netting agreement or similar arrangement	17,546			(17,546		)	—
	Not subject to a master netting agreement or similar arrangement:
	Commodity derivative:
	Oil and Gas - Crude Basis Swaps	—			—			—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	—			—			—
	Utilities	—			—			—
	Total derivative assets not subject to a master netting agreement or similar arrangement	—			—			—
	Total derivative assets	$	17,546		$	(17,546	)	$	—
	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 - Crude Basis Swaps	$	—		$	—		$	—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	473			(473		)	—
	Utilities	19,303			(19,303		)	—
	Interest Rate Swaps	—			—			—
	Total derivative liabilities subject to a master netting agreement or similar arrangement	19,776			(19,776		)	—
	Not subject to a master netting agreement or similar arrangement:
	Commodity derivative:
	Oil and Gas - Crude Basis Swaps	—			—			—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	—			—			—
	Utilities	—			—			—
	Interest Rate Swaps	6,020			—			6,020
	Total derivative liabilities not subject to a master netting agreement or similar arrangement	6,020			—			6,020
	Total derivative liabilities	$	25,796		$	(19,776	)	$	6,020
	Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2013 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 - Crude Basis Swaps	$	75		$	(75	)	$	—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	815			(815		)	—
	Utilities	3,030			(2,368		)	662
	Total derivative assets subject to a master netting agreement or similar arrangement	3,920			(3,258		)	662
	Not subject to a master netting agreement or similar arrangement:
	Commodity derivative:
	Oil and Gas - Crude Basis Swaps	55			—			55
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	—			—			—
	Utilities	—			—			—
	Total derivative assets not subject to a master netting agreement or similar arrangement	55			—			55
	Total derivative assets	$	3,975		$	(3,258	)	$	717
	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 - Crude Basis Swaps	$	1,229		$	(1,229	)	$	—
	Oil and Gas - Crude Options	—			—			—
	Oil and Gas - Natural Gas Basis Swaps	531			(531		)	—
	Utilities	9,100			(9,100		)	—
	Interest Rate Swaps	—			—			—
	Total derivative liabilities subject to a master netting agreement or similar arrangement	10,860			(10,860		)	—
	Not subject to a master netting agreement or similar arrangement:
	Commodity derivative:
	Oil and Gas - Crude Basis Swaps	—			—			—
Oil and Gas - Crude Options	—			—			—
Oil and Gas - Natural Gas Basis Swaps	—			—			—
Utilities	—			—			—
Interest Rate Swaps	9,088			—			9,088
Total derivative liabilities not subject to a master netting agreement or similar arrangement	9,088			—			9,088
Total derivative liabilities	$	19,948		$	(10,860	)	$	9,088
Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2014 were (in thousands):
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets			Cash Collateral Received			Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—		$	—		$	—
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			—			—
		$	—		$	—		$	—
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities			Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—		$	(4,392	)	$	(4,392	)
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			(3,093		)	(3,093		)
Interest Rate Swaps	Counterparty F	6,020			—			6,020
		$	6,020		$	(7,485	)	$	(1,465	)
Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2013 were (in thousands):
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Assets			Cash Collateral Received			Net Amount with Counterparty
Assets:
Oil and Gas	Counterparty A	$	—		$	—		$	—
Oil and Gas	Counterparty B	55			—			55
Utilities	Counterparty A	662			—			662
		$	717		$	—		$	717
					Gross Amounts Not Offset on Consolidated Balance Sheets
Contract Type		Net Amount of Total Derivative Liabilities			Cash Collateral Paid			Net Amount with Counterparty
Liabilities:
Oil and Gas	Counterparty A	$	—		$	(1,631	)	$	(1,631	)
Oil and Gas	Counterparty B	—			—			—
Utilities	Counterparty A	—			(3,390		)	(3,390		)
Interest Rate Swap	Counterparty F	9,088			—			9,088
		$	9,088		$	(5,021	)	$	4,067

Fair_Value_Of_Financial_Instru1

Fair Value Of Financial Instruments: Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value of financial instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 9, were as follows at December 31 (in thousands):
		2014				2013
		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	Cash and cash equivalents (a)	$	21,218	$	21,218	$	7,841	$	7,841
	Restricted cash and equivalents (a)	$	2,056	$	2,056	$	2	$	2
	Notes payable (a)	$	75,000	$	75,000	$	82,500	$	82,500
	Long-term debt, including current maturities (b)	$	1,542,589	$	1,734,555	$	1,396,948	$	1,491,422
	_______________
	(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
	(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Stock_Stock_Tables

Stock: Stock (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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 was as follows for the years ended December 31 (in thousands):
		2014			2013			2012
	Stock-based compensation expense	$	9,329		$	12,595		$	8,271
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):
		2014			2013
	Shares Issued	52			67
	Weighted Average Price	$	54.99		$	46.78
	Unissued Shares Available	474			286
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Compensation, Stock Options, Activity	A summary of the status of the stock options at December 31, 2014 was as follows:
		Shares		Weighted-Average Exercise Price				Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
		(in thousands)						(in years)	(in thousands)
	Balance at beginning of period	61		$	33.25
	Granted (a)	81		54.29
	Forfeited/canceled	—		—
	Expired	—		—
	Exercised	(8	)	30.87
	Balance at end of period	134		$	46.12			8.2	$	1,027
	Exercisable at end of period	46		$	32.63			6.5	$	944
	___________________________
	(a)	The grant date fair value of the 2014 awards was $12.58 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.1% risk free interest rate, 29.4% expected price volatility, 2.9% expected dividend yield and a 7 year expected life.
	The table below provides details of our option plans at December 31 (in thousands):
		2014			2013			2012
	Summary of Stock Options
	Unrecognized compensation expense	$	816		$	130		$	218
	Intrinsic value of options exercised (a)	$	199		$	789		$	623
	Net cash received from exercise of options	$	237		$	2,046		$	2,839
	Tax benefit realized from exercise of shares (b)	$	70		$	276		$	218
	_____________________
	(a)	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
	(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.
Restricted Stock [Member]
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 at December 31, 2014, was as follows:
		Restricted Stock		Weighted-Average Grant Date Fair Value
		(in thousands)
	Restricted Stock at beginning of period	262		$	36.76
	Granted	99		54.34
	Vested	(114	)	35.25
	Forfeited	(14	)	43.17
	Restricted Stock at end of period	233		$	44.6
	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)
	2014	$	54.34		$	6,114
	2013	$	40.56		$	5,842
	2012	$	34.99		$	3,781
Performance Shares [Member]
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
	1-Jan-12	January 1, 2012 - December 31, 2014	64	0%	200%
	1-Jan-13	January 1, 2013 - December 31, 2015	61	0%	200%
	1-Jan-14	January 1, 2014 - December 31, 2016	44	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 (b)
		Shares					Shares		31-Dec-14
		(in thousands)					(in thousands)
	Performance Shares balance at beginning of period	93		$	31.34		93
	Granted	23		55.18			23
	Forfeited	(1	)	40.12			(1	)
	Vested	(31	)	25.92			(31	)
	Performance Shares balance at end of period	84		$	39.58		84		$	82.42
	_____________________
	(a)	The grant date fair values for the performance shares granted in 2014, 2013 and 2012 were determined by Monte Carlo simulation using a blended volatility of 23%, 20% and 21%, 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.
	(b)	The weighted-average fair value for the liability portion at December 31, 2014 was determined by the actual performance for the 2012 to 2014 performance period at the top of the peer group resulting in a 200% of target payout, and determined by Monte Carlo simulations for the 2013 to 2015 performance period and 2014 to 2016 performance period projecting a 157% and 51% of target payouts, respectively.
	The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:
		Weighted Average Grant Date Fair Value
	31-Dec-14	$	55.18
	31-Dec-13	$	35.85
	31-Dec-12	$	32.26
	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, 2011 to December 31, 2013	2014	59		$	3,011		$	6,020
	January 1, 2010 to December 31, 2012	2013	63		$	2,267		$	4,533
	January 1, 2009 to December 31, 2011	2012	—		$	—		$	—

Operating_Leases_Operating_Lea

Operating Leases: Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2014
Leases, Operating [Abstract]
Operating Leases of Lessor Disclosure	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):
		2014		2013		2012
	Rent expense	$	6,932	$	7,169	$	6,839
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):
	2015	$	9,962
	2016	$	2,045
	2017	$	1,852
	2018	$	1,829
	2019	$	1,632
	Thereafter	$	3,735

Income_Taxes_Income_Taxes_Tabl

Income Taxes: Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
		2014			2013			2012
	Current:
	Federal	$	(2,319	)	$	(2,003	)	$	4,972
	State	(1,288		)	(173		)	3,712
		(3,607		)	(2,176		)	8,684
	Deferred:
	Federal	63,645			56,963			39,876
	State	5,563			7,033			68
	Tax credit amortization	(206		)	(212		)	(228		)
		69,002			63,784			39,716
		$	65,395		$	61,608		$	48,400
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):
		2014			2013
	Deferred tax assets:
	Regulatory liabilities	$	49,243		$	33,172
	Employee benefits	26,714			28,724
	Federal net operating loss	213,466			166,095
	Asset impairment	55,067			55,124
	Other deferred tax assets(a)	76,005			59,078
	Less: Valuation allowance	(5,017		)	(1,806		)
	Total deferred tax assets	415,478			340,387
	Deferred tax liabilities:
	Accelerated depreciation, amortization and other plant-related differences	(679,911		)	(598,415		)
	Regulatory assets	(25,340		)	(24,581		)
	Mining development and oil exploration	(97,198		)	(69,799		)
	State deferred tax liability	(37,489		)	(30,293		)
	Deferred costs	(35,284		)	(15,593		)
	Other deferred tax liabilities	(15,684		)	(15,104		)
	Total deferred tax liabilities	(890,906		)	(753,785		)
	Net deferred tax liability	$	(475,428	)	$	(413,398	)
	_______________
	(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.
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:
		2014		2013		2012
	Federal statutory rate	35	%	35	%	35	%
	State income tax (net of federal tax effect)	1.1		2.4		2
	Amortization of excess deferred income taxes and investment tax credits	(0.1	)	(0.1	)	(0.2	)
	Percentage depletion in excess of cost	(1.0	)	(1.0	)	(1.3	)
	Equity AFUDC	(0.1	)	—		—
	Tax credits	(0.1	)	(0.5	)	—
	Accounting for uncertain tax positions adjustment	(0.1	)	0.7		0.8
	Flow-through adjustments (a)	(0.9	)	(0.9	)	(1.3	)
	Other tax differences	(0.1	)	(0.9	)	0.4
		33.7	%	34.7	%	35.4	%
	_________________________
	(a)	The flow-through adjustments relate 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. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred in 2010. 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 a tax benefit consistent with the flow-through method.
Summary of Operating Loss Carryforwards	At December 31, 2014, 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		$	618,195			2019	to	2034
	State Net Operating Loss Carryforward		$	513,418			2015	to	2034
Summary of Income Tax Contingencies	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, 2012	$	49,327
	Additions for prior year tax positions	111
	Reductions for prior year tax positions	(8,906		)
	Additions for current year tax positions	151
	Settlements	—
	Ending balance at December 31, 2012	40,683
	Additions for prior year tax positions	1,526
	Reductions for prior year tax positions	(4,578		)
	Additions for current year tax positions	—
	Settlements	—
	Ending balance at December 31, 2013	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
State and Local Jurisdiction [Member]
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, 2014, we had the following state tax credit carryforwards (in thousands):
	State Tax Credit Carryforwards				Expiration Year
	Investment tax credit	$	14,793		2023	to	2025
	Research and development	$	155		No expiration

Other_Comprehensive_Income_Com

Other Comprehensive Income: Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Reclassification out of Accumulated Other Comprehensive Income	The components of the reclassification adjustments for the period, net of tax, included in Other comprehensive income were as follows (in thousands):
		Location on the Consolidated Statements of Income	Amount Reclassified from AOCI
			31-Dec-14			31-Dec-13
	Gains and losses on cash flow hedges:
	Interest rate swaps	Interest expense	$	3,669		$	6,989
	Commodity contracts	Revenue	1,995			(927		)
			5,664			6,062
	Income tax	Income tax benefit (expense)	(2,344		)	(2,016		)
	Total reclassification adjustments related to cash flow hedges, net of tax		$	3,320		$	4,046
	Amortization of defined benefit plans:
	Prior service cost	Utilities - Operations and maintenance	$	(102	)	$	(125	)
		Non-regulated energy operations and maintenance	(115		)	(128		)
	Actuarial gain (loss)	Utilities - Operations and maintenance	630			1,693
		Non-regulated energy operations and maintenance	364			1,098
			777			2,538
	Income tax	Income tax benefit (expense)	(272		)	(883		)
	Total reclassification adjustments related to defined benefit plans, net of tax		$	505		$	1,655
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within Accumulated other comprehensive income (loss) 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, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)
	Other comprehensive income (loss)	1,695			10,531			(9,848		)	2,378
	As of December 31, 2014	$	(4,930	)	$	10,023		$	(20,137	)	$	(15,044	)
		Derivatives Designated as Cash Flow Hedges
		Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	As of December 31, 2012	$	(16,313	)	$	600		$	(19,775	)	$	(35,488	)
	Other comprehensive income (loss)	9,688			(1,108		)	9,486			18,066
	As of December 31, 2013	$	(6,625	)	$	(508	)	$	(10,289	)	$	(17,422	)

Supplemental_Disclosure_of_Cas1

Supplemental Disclosure of Cash flow Information: Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information
	Years ended December 31,	2014			2013			2012
		(in thousands)
	Non-cash investing activities and financing from continuing operations -
	Property, plant and equipment acquired with accrued liabilities	$	52,584		$	59,811		$	35,556
	Increase (decrease) in capitalized assets associated with asset retirement obligations	$	(5,634	)	$	1,235		$	5,743
	Cash (paid) refunded during the period for continuing operations-
	Interest (net of amount capitalized)	$	(69,239	)	$	(108,361	)	$	(116,593	)
	Income taxes, net	$	(413	)	$	(4,573	)	$	(3,027	)

Employee_Benefit_Plans_Employe

Employee Benefit Plans: Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
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:
		2014		2013
	Equity	27	%	26	%
	Real estate	5		4
	Fixed income	58		58
	Cash	2		1
	Hedge funds	8		11
	Total	100	%	100	%
Schedule of Defined Contribution Plans Contributions	Contributions for the years ended December 31 were as follows (in thousands):
		2014			2013
	Defined Contribution Plan
	Company Retirement Contribution	$	4,187		$	2,775
	Matching contributions - Defined Contribution Plans	$	9,254		$	8,524
		2014			2013
	Defined Benefit Plans
	Defined Benefit Pension Plans	$	10,200		$	12,500
	Non-Pension Defined Benefit Postretirement Healthcare Plans	$	3,163		$	5,123
	Supplemental Non-Qualified Defined Benefit Plans	$	1,553		$	1,345
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Level 3 assets for the period ended December 31 (in thousands):
		2014			2013
	Balance, beginning of period	$	38,188		$	7,770
	Purchase	454			29,000
	Unrealized gain (loss)	1,789			1,508
	Realized gain (loss)	322			(77		)
	Settlements	(6,000		)	(13		)
	Balance, end of period	$	34,753		$	38,188
Fair Value, Assets Measured on Recurring Basis	The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands):
		Fair Value at			Valuation	Level 3	Range (Weighted)
		31-Dec-14			Technique	Input	Average
	Assets:
	Common Collective Trust - Real Estate (a)	$	9,719		Market Approach	Redemption Restriction	N/A
	Hedge Funds (b)	$	25,034		Market Approach	Redemption Restriction	N/A
	_____________
	(a)	The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.
	(b)	The fair value of the Hedge Funds is determined based on pricing provided or reviewed by the third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.
Schedule of Changes in Projected Benefit Obligations	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 accumulated other comprehensive income (in thousands):
	Benefit Obligations
			Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans							Non-pension Defined Benefit Postretirement Plans
			2014			2013			2014			2013				2014			2013
	Change in benefit obligation:
	Projected benefit obligation at beginning of year		$	321,400		363,235			$	32,960		$	34,393			$	45,778		$	46,681
	Service cost		5,448			6,433			2,543			1,392				1,700			1,674
	Interest cost		15,852			15,300			1,447			1,328				1,919			1,669
	Actuarial (gain) loss	(a)	55,384			(38,252		)	5,814			(2,808		)		2,275			(3,379		)
	Amendments (b)		—			—			—			—				—			1,585
	Benefits paid	(c)	(20,312		)	(25,316		)	(1,553		)	(1,345		)		(3,163		)	(5,123		)
	Medicare Part D accrued		—			—			—			—				(99		)	470
	Plan participants’ contributions		—			—			—			—				632			2,201
	Projected benefit obligation at end of year		$	377,772		$	321,400		$	41,211		$	32,960			$	49,042		$	45,778
	____________________
	(a)	Change from 2013 reflects a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
	(b)	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.
	(c) Benefits paid include payments made to terminated vested employees who elected lump-sum offerings of $6.1 million in 2014 and $13 million in 2013.
Schedule of Changes in Fair Value of Plan Assets	A reconciliation of the fair value of Plan assets was as follows (in thousands):
		Defined Benefit Pension Plans								Supplemental Non-qualified Defined Benefit Retirement Plans							Non-pension Defined Benefit Postretirement Plans (a)
		2014			2013					2014			2013				2014			2013
	Beginning market value of plan assets	$	280,362		$	268,816				$	—		$	—			$	4,546		$	4,351
	Investment income (loss)	29,283			24,362					—			—				(43		)	8
	Employer contributions	10,200			12,500					—			—				2,733			1,923
	Retiree contributions	—			—					—			—				632			1,533
	Benefits paid	(20,312		)	(25,316		)	(b)		—			—				(3,163		)	(3,269		)
	Plan administrative expenses	—			—					—			—				—			—
	Ending market value of plan assets	$	299,533		$	280,362				$	—		$	—			$	4,705		$	4,546
	____________________
	(a)	Assets of VEBA.
	(b)	Benefits paid include payments made to terminated vested employees who elected a lump-sum offering of $6.1 million in 2014 and $13 million in 2013.
Schedule of Amounts Recognized in Balance Sheet	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
		2014			2013				2014			2013				2014			2013
	Regulatory assets	$	78,864		$	48,419			$	—		$	—			$	7,137		$	5,535
	Current liabilities	$	—		$	—			$	1,486		$	1,491			$	3,273		$	2,802
	Non-current liabilities	$	78,239		$	41,034			$	39,725		$	32,033			$	41,002		$	38,412
	Regulatory liabilities	$	—		$	—			$	—		$	—			$	2,983		$	3,141
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
		2014			2013				2014			2013				2014			2013
	Accumulated benefit obligation - Black Hills Corporation	$	135,582		$	110,847			$	29,843		$	27,380			$	12,809		$	12,101
	Accumulated benefit obligation - Black Hills Energy	213,398			182,295				386			513				25,456			25,467
	Accumulated benefit obligation - Cheyenne Light	—			—				—			—				10,777			8,210
	Total Accumulated Benefit Obligation	$	348,980		$	293,142			$	30,229		$	27,893			$	49,042		$	45,778
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
		2014			2013			2012				2014			2013			2012				2014			2013			2012
	Service cost	$	5,448		$	6,433		$	5,720			$	1,498		$	1,392		$	889			$	1,700		$	1,674		$	1,610
	Interest cost	15,852			15,300			14,747				1,447			1,328			1,410				1,919			1,669			2,093
	Expected return on assets	(18,065		)	(18,615		)	(16,334		)		—			—			—				(85		)	(79		)	(78		)
	Amortization of prior service cost	62			63			89				2			2			3				(428		)	(500		)	(500		)
	Recognized net actuarial loss (gain)	4,806			12,250			9,630				498			793			807				160			482			887
	Net periodic expense	$	8,103		$	15,431		$	13,852			$	3,445		$	3,515		$	3,109			$	3,266		$	3,246		$	4,012
Schedule of Net Periodic Benefit Cost Not yet Recognized	In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), 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
		2014			2013				2014			2013				2014			2013
	Net (gain) loss	$	10,996		$	4,842			$	8,396		$	4,939			$	1,904		$	1,648
	Prior service cost (gain)	51			64				8			9				(1,218		)	(1,213		)
	Total accumulated other comprehensive (income) loss	$	11,047		$	4,906			$	8,404		$	4,948			$	686		$	435
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2015 are as follows (in thousands):
		Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	Net loss	$	7,174			$	703			$	295
	Prior service cost (credit)	38				1				(278		)
	Total net periodic benefit cost expected to be recognized during calendar year 2015	$	7,212			$	704			$	17
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:	2014		2013		2012			2014		2013		2012			2014		2013		2012
	Discount rate	4.2	%	5.05	%	4.3	%		3.64	%	4.21	%	3.44	%		3.92	%	4.62	%	3.85	%
	Rate of increase in compensation levels	3.78	%	3.78	%	3.84	%		5	%	5	%	5	%		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:	2014		2013		2012			2014		2013		2012			2014		2013		2012
	Discount rate:
	Black Hills Corporation	5.1	%	4.35	%	4.68	%		4.68	%	3.88	%	4.7	%		4.45	%	3.65	%	4.35	%
	Black Hills Energy	5	%	4.25	%	4.6	%		3.75	%	3	%	3.9	%		4.25	%	3.5	%	4.35	%
	Cheyenne Light	N/A		N/A		N/A			N/A		N/A		N/A			5.15	%	4.4	%	4.65	%
	Expected long-term rate of return on assets (a)	6.75	%	7.25	%	7.25	%		N/A		N/A		N/A			2	%	2	%	2	%
	Rate of increase in compensation levels	3.78	%	3.78	%	3.75	%		5	%	5	%	5	%		N/A		N/A		N/A
	_____________________________
	(a)	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.
Schedule of Health Care Cost Trend Rates	The healthcare benefit obligation was determined at December 31 as follows:
		Black Hills Corporation		Black Hills Energy		Cheyenne Light
	2014
	Healthcare trend rate pre-65
	Trend for next year	7.5	%	7.5	%	7.5	%
	Ultimate trend rate	4.5	%	4.5	%	4.5	%
	Year Ultimate Trend Reached	2027		2027		2027
	Healthcare trend rate post-65
	Trend for next year	6.25	%	6.25	%	6.25	%
	Ultimate trend rate	4.5	%	4.5	%	4.5	%
	Year Ultimate Trend Reached	2024		2024		2024
	2013
	Healthcare trend rate pre-65
	Trend for next year	7.5	%	7.5	%	7.5	%
	Ultimate trend rate	4.5	%	4.5	%	4.5	%
	Year Ultimate Trend Reached	2027		2027		2027
	Healthcare trend rate post-65
	Trend for next year	6.25	%	6.25	%	6.25	%
	Ultimate trend rate	4.5	%	4.5	%	4.5	%
	Year Ultimate Trend Reached	2026		2026		2026
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 Retiree Healthcare Plans (in thousands):
	Change in Assumed Trend Rate		Impact on December 31, 2014 Accumulated Postretirement				Impact on 2014 Service
			Benefit Obligation				and Interest Cost
	Increase 1%		$	2,635			$	168
	Decrease 1%		$	(2,166	)		$	(136	)
Schedule of Expected Benefit Payments	The following benefit payments, which reflect future service, are expected to be paid (in thousands):
		Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plan				Non-Pension Defined Benefit Postretirement Healthcare Plans
	2015	$	14,712			$	1,486			$	3,921
	2016	$	15,629			$	1,573			$	4,011
	2017	$	16,561			$	1,627			$	4,057
	2018	$	17,556			$	1,670			$	4,169
	2019	$	18,741			$	1,780			$	4,236
	2020-2024	$	109,147			$	8,901			$	19,877
Pension Plans, Defined Benefit [Member]
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	31-Dec-14
		Level 1				Level 2				Level 3				Total
	AXA Equitable General Fixed Income	$	—			$	541			$	—			$	541
	Common Collective Trust - Cash and Cash Equivalents	—				4,013				—				4,013
	Common Collective Trust - Equity	—				81,636				—				81,636
	Common Collective Trust - Fixed Income	—				174,726				—				174,726
	Common Collective Trust - Real Estate	—				3,864				9,719				13,583
	Hedge Funds	—				—				25,034				25,034
	Total investments measured at fair value	$	—			$	264,780			$	34,753			$	299,533
	Defined Benefit Pension Plans	31-Dec-13
		Level 1				Level 2				Level 3				Total
	AXA Equitable General Fixed Income	$	—			$	1,056			$	—			$	1,056
	Common Collective Trust - Cash and Cash Equivalents	—				1,253				—				1,253
	Common Collective Trust - Equity	—				73,726				—				73,726
	Common Collective Trust - Fixed Income	—				162,747				—				162,747
	Common Collective Trust - Real Estate	—				3,392				8,541				11,933
	Hedge Funds	—				—				29,647				29,647
	Total investments measured at fair value	$	—			$	242,174			$	38,188			$	280,362
Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Allocation of Plan Assets
	Non-pension Defined Benefit Postretirement Healthcare Plans	31-Dec-14
		Level 1				Level 2				Level 3				Total
	Registered Investment Company Trust - Money Market Mutual Fund	$	—			$	4,705			$	—			$	4,705
	Total investments measured at fair value	$	—			4,705				$	—			$	4,705
	Non-pension Defined Benefit Postretirement Healthcare Plans	31-Dec-13
		Level 1				Level 2				Level 3				Total
	Registered Investment Company Trust - Money Market Mutual Fund	$	—			$	4,546			$	—			$	4,546
	Total investments measured at fair value	$	—			$	4,546			$	—			$	4,546

Commitments_And_Contingencies_

Commitments And Contingencies: Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Long-term Purchase Commitment	Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
		2014		2013		2012
	PPA with PacifiCorp	$	13,943	$	13,026	$	13,224
	Transmission services agreement with PacifiCorp	$	1,227	$	1,384	$	1,215
	PPA with Happy Jack	$	3,919	$	3,772	$	1,988
	PPA with Silver Sage	$	4,798	$	4,809	$	3,269
	Busch Ranch Wind Project	$	1,998	$	1,856	$	502
	PPAs with Cargill (a)	$	9,286	$	12,291	$	14,236
	____________________
	(a)    The 2013 and 2012 PPAs were one year contracts replaced by subsequent one year contracts upon expiration.
Unrecorded Unconditional Purchase Obligations Disclosure	The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements and natural gas delivery commitments (in thousands):
	2015	$	183,116
	2016	$	131,716
	2017	$	121,867
	2018	$	69,000
	2019	$	35,905
	Thereafter	$	153,395

Guarantees_Guarantees_Tables

Guarantees: Guarantees (Tables)	12 Months Ended
	Dec. 31, 2014
Guarantees [Abstract]
Schedule of Guarantor Obligations	We had the following guarantees in place as of (in thousands):
		Maximum Exposure at
	Nature of Guarantee	31-Dec-14		Expiration
	Indemnification for subsidiary reclamation/surety bonds (a)	$	63,900	Ongoing
	_______________________
	(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_Unaudited1

Oil and Gas Reserves (Unaudited): Oil and Gas Exploration and Production Industries Disclosure (Tables)	12 Months Ended
	Dec. 31, 2014
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):
		2014			2013			2012
	Acquisition of properties:
	Proved	$	4,881		$	234		$	2,437
	Unproved	5,056			6,022			33,052
	Exploration costs	54,355			12,817			115
	Development costs	52,262			48,641			73,877
	Asset retirement obligations incurred	68			143			158
	Total costs incurred	$	116,622		$	67,857		$	109,639
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	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, 2014, 2013 and 2012 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.
		2014										2013						2012
		Oil			Gas			NGL				Oil			Gas			Oil			Gas
		(in Mbbls of oil and NGL, and MMcf of gas)
	Proved developed and undeveloped reserves:
	Balance at beginning of year	3,921			63,190			—				4,116			55,985			6,223			95,904
	Production (a)	(337		)	(7,156		)	(135		)		(336		)	(6,984		)	(560		)	(8,686		)
	Additions - acquisitions (sales) (b)	(40		)	(61		)	—				(30		)	(46		)	(2,025		)	(3,070		)
	Additions - extensions and discoveries	733			11,003			182				379			10,456			449			2,898
	Revisions to previous estimates	(1		)	(1,536		)	1,673				(208		)	3,779			29			(31,061		)
	Balance at end of year	4,276			65,440			1,720				3,921			63,190			4,116			55,985
	Proved developed reserves at end of year included above	3,780			57,427			1,530				3,689			60,224			3,929			55,708
	Proved undeveloped reserves at the end of year included in above	496			8,013			191				232			2,966			187			279
	NYMEX prices	$	94.99		$	4.35		$	—		(c)	$	96.94		$	3.67		$	94.71		$	2.76
	Well-head reserve prices	$	85.8		$	3.33		$	34.81			$	89.79		$	3.45		$	85.31		$	2.24
	________________________
	(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.
	(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.
	(c)	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, iso butane, 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.
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, 2014 were:
		Proved Reserves (in Bcfe)		Gross PUD Locations		Future Development Costs (in millions)
	Existing 2013:
	Williston	1.8		21		$	8.6
	Piceance	2.3		1		$	6.4
	San Juan	0.6		1		$	0.9
	Year End Total 2013	4.7		23		$	15.9
	Dropped 2013:
	San Juan	(0.6	)	(1	)	$	(0.9	)
	Drilled in 2014:
	Williston	(0.6	)	(7	)	$	(3.9	)
	Sold:
	Williston	(0.3	)	(2	)	$	(0.7	)
	Added in 2014:
	Williston	0.2		18		$	1
	Powder River	2		1		$	13
	Piceance	6.7		2		$	17.5
		8.9		21		$	31.5
	Total Proved Undeveloped	12.1		34		$	41.9
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	Following is information concerning capitalized costs for the years ended December 31 (in thousands):
		2014			2013			2012
	Unproved oil and gas properties	$	75,329		$	62,553		$	59,526
	Proved oil and gas properties	807,518			725,345			662,444
	Gross capitalized costs	882,847			787,898			721,970
	Accumulated depreciation, depletion and amortization and valuation allowances (a)	(578,108		)	(555,263		)	(534,777		)
	Net capitalized costs	$	304,739		$	232,635		$	187,193
	__________________
	(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.
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):
		2014			2013			2012
	Revenue	$	55,114		$	54,884		$	79,072
	Production costs	22,155			20,140			23,483
	Gain on sale of assets	—			—			(29,129		)
	Depreciation, depletion and amortization and valuation provisions	26,626			20,611			37,323
	Impairment of long-lived assets	—			—			26,868
	Total costs	48,781			40,751			58,545
	Results of operations from producing activities before tax	6,333			14,133			20,527
	Income tax benefit (expense)	(2,185		)	(4,876		)	(7,082		)
	Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	4,148		$	9,257		$	13,445
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, 2014 and notes the year in which the associated costs were incurred (in thousands):
		2014			2013			2012			Prior			Total
	Leasehold acquisition cost	$	16,077		$	4,889		$	35,823		$	13,412		$	70,201
	Exploration cost	23,954			10,212			—			—			34,166
	Capitalized interest	207			748			360			3,813			5,128
	Total	$	40,238		$	15,849		$	36,183		$	17,225		$	109,495
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):
		2014			2013			2012
	Future cash inflows	$	675,973		$	602,501		$	502,769
	Future production costs	(245,180		)	(213,578		)	(186,695		)
	Future development costs, including plugging and abandonment	(45,123		)	(40,557		)	(8,462		)
	Future income tax expense	(29,523		)	(81,566		)	(69,877		)
	Future net cash flows	356,147			266,800			237,735
	10% annual discount for estimated timing of cash flows	(173,125		)	(107,375		)	(101,632		)
	Standardized measure of discounted future net cash flows	$	183,022		$	159,425		$	136,103
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):
		2014			2013			2012
	Standardized measure - beginning of year	$	159,425		$	136,103		$	203,357
	Sales and transfers of oil and gas produced, net of production costs	(32,139		)	(35,932		)	(48,905		)
	Net changes in prices and production costs	(28,544		)	15,126			(42,639		)
	Extensions, discoveries and improved recovery, less related costs	17,582			29,574			19,870
	Changes in future development costs	3,195			(12,216		)	43,854
	Development costs incurred during the period	2,079			3,554			21,931
	Revisions of previous quantity estimates	23,722			12,851			(86,277		)
	Accretion of discount	18,437			15,126			25,509
	Net change in income taxes	19,265			(3,892		)	36,578
	Purchases of reserves	—			—			—
	Sales of reserves (a)	—			(869		)	(37,175		)
	Standardized measure - end of year	$	183,022		$	159,425		$	136,103
	________
	(a)	Reflects sale of Williston Basin assets in 2012.

Sale_Of_Operating_Assets_and_D1

Sale Of Operating Assets and Discontinued Operations: Sale of Operating Assets and Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Williston Basin Assets [Member]
Significant Acquisitions and Disposals [Line Items]
Cash proceeds from sale of operating assets	Net cash proceeds, subsequent to the true-up of all post-closing adjustments, were as follows (in thousands):
	Cash proceeds received on date of sale	$	243,314
	Adjusted for:
	Post close adjustments	2,793
	Transaction adviser fees	(1,400		)
	Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
	Net cash proceeds	$	227,860
	_____________
	*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.
Energy Marketing [Member]
Significant Acquisitions and Disposals [Line Items]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):
	For the Years Ended December 31,	2013			2012
	Revenue	$	—		$	(604	)
	Pre-tax income (loss) from discontinued operations	—			(6,061		)
	Pre-tax gain (loss) on sale	(1,391		)	(4,184		)
	Income tax (expense) benefit	507			3,268
	Income (loss) from discontinued operations, net of tax (a)	$	(884	)	$	(6,977	)
	________
	(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended December 31, 2012.

Quarterly_Historical_Data_Unau1

Quarterly Historical Data (Unaudited): Quarterly Historical Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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 2014 and 2013.
		First Quarter		Second Quarter		Third		Fourth Quarter
						Quarter
		(in thousands, except per share amounts, dividends and common stock prices)
	2014
	Revenue	$	460,169	$	283,237	$	272,087	$	378,077
	Operating income	$	89,598	$	46,577	$	54,404	$	69,951
	Income (loss) from continuing operations	$	48,118	$	19,820	$	26,836	$	34,007
	Net income (loss) available for common stock	$	48,118	$	19,820	$	26,836	$	34,007
	Income (loss) per share - Basic	$	1.09	$	0.45	$	0.6	$	0.77
	Income (loss) per share - Diluted	$	1.08	$	0.44	$	0.6	$	0.76
	Dividends paid per share	$	0.39	$	0.39	$	0.39	$	0.39
	Common stock prices - High	$	59.05	$	61.41	$	62.13	$	57.17
	Common stock prices - Low	$	51.09	$	55.23	$	47.87	$	47.11
		First Quarter		Second Quarter		Third		Fourth
						Quarter		Quarter
		(in thousands, except per share amounts, dividends and common stock prices)
	2013
	Revenue	$	380,671	$	279,826	$	259,907	$	355,448
	Operating income	$	79,846	$	49,037	$	55,566	$	71,103
	Income (loss) from continuing operations (a) (b)	$	43,197	$	30,518	$	23,124	$	19,007
	Income (loss) from discontinued operations	$	—	$	—	$	—	$	(884	)
	Net income (loss) available for common stock (a) (b)	$	43,197	$	30,518	$	23,124	$	18,123
	Income (loss) per share for continuing operations - Basic	$	0.98	$	0.69	$	0.52	$	0.43
	Income (loss) per share for discontinued operations - Basic	—		—		—		(0.02		)
	Income (loss) per share - Basic	$	0.98	$	0.69	$	0.52	$	0.41
	Income (loss) per share for continuing operations - Diluted	$	0.97	$	0.69	$	0.52	$	0.43
	Income (loss) per share for discontinued operations - Diluted	—		—		—		(0.02		)
	Income (loss) per share - Diluted	$	0.97	$	0.69	$	0.52	$	0.41
	Dividends paid per share	$	0.38	$	0.38	$	0.38	$	0.38
	Common stock prices - High	$	44.32	$	50.53	$	55.09	$	54.83
	Common stock prices - Low	$	36.89	$	43.19	$	46.62	$	47
	__________________________
	(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
	(b)	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.

Business_Description_And_Signi3

Business Description And Significant Accounting Policies: Business Description (Details)	12 Months Ended
	Dec. 31, 2014
	Business_Group
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Business Groups	2

Business_Description_And_Signi4

Business Description And Significant Accounting Policies: Accounts Receivable (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	($1,516)	($1,237)
Accounts receivable, net	189,992	177,573
Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,555	604
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	-722	-666
Accounts receivable, net	85,466	75,594
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	-781	-558
Accounts receivable, net	92,159	89,799
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,369	1,722
Coal Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	3,151	1,711
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	-13	-13
Accounts receivable, net	5,292	8,143
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	119,488	113,792
Billed Revenues [Member] | Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,555	604
Billed Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	59,714	52,437
Billed Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	47,394	49,162
Billed Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,369	1,722
Billed Revenues [Member] | Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,151	1,711
Billed Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	5,305	8,156
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	72,020	65,018
Unbilled Revenues [Member] | Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	26,474	23,823
Unbilled Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	45,546	41,195
Unbilled Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] | Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$0	$0

Business_Description_And_Signi5

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$49,555	$50,196
Fuel - Electric Utilities	6,637	6,213
Natural gas in storage held for distribution	34,999	32,069
Total materials, supplies and fuel	$91,191	$88,478

Business_Description_And_Signi6

Business Description And Significant Accounting Policies: Goodwill (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$353,396	$353,396
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	353,396	353,396
Electric Utilities [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	250,487	250,487
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	250,487	250,487
Gas Utilities [Member]
Goodwill [Roll Forward]
Goodwill, Additions (adjustments)	0	0
Power Generation [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765	8,765
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	8,765	8,765
Aquila Transaction [Member] | Electric Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	72.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	246,000
Aquila Transaction [Member] | Gas Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	28.00%
Goodwill [Roll Forward]
Goodwill, Beginning Balance			94,144
Goodwill, Ending Balance	$94,144	$94,144	$94,144

Business_Description_And_Signi7

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Finite-Lived Intangible Assets, Useful Life, Maximum (years)	20 years
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$3,397,000		$3,620,000	$3,843,000
Intangible assets, additions (adjustments)	0		0	0
Intangible assets, amortization expense	-221,000	[1]	-223,000	-223,000
Intangible assets, net, ending balance	3,176,000		3,397,000	3,620,000
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	200,000
Future Amortization Expense, Year Two	200,000
Future Amortization Expense, Year Three	200,000
Future Amortization Expense, Year Four	200,000
Future Amortization Expense, Year Five	$200,000
[1]	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

Business_Description_And_Signi8

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$257,839		$162,648
Regulatory liabilities	148,831		120,156
Deferred energy, fuel and gas cost adjustments [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period	1 year
Regulatory liabilities	6,496	[1]	11,708	[1]
Cost of removal [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period	44 years
Regulatory liabilities	78,249	[1]	64,970	[1]
Other regulatory liabilities [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period	25 years
Regulatory liabilities	10,947	[2]	9,047	[2]
Deferred energy, fuel and gas cost adjustments [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	1 year
Regulatory assets	23,820	[1],[3]	16,775	[1],[3]
Deferred gas cost adjustments and gas price derivatives [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	2 years
Regulatory assets	37,471	[1],[3]	4,799	[1],[3]
Price Risk Derivative [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	7 years
Regulatory assets	18,740	[1]	7,567	[1]
Allowance For Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	45 years
Regulatory assets	12,358	[4]	12,315	[4]
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	12 years
Regulatory liabilities maximum amortization period	12 years
Regulatory assets	97,126	[2],[5]	67,059	[2]
Regulatory liabilities	53,139	[2],[5]	34,431	[2]
Environmental [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	1,314	[1]	1,800	[1]
Asset retirement obligations [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	44 years
Regulatory assets	3,287	[1]	3,266	[1]
Bond issuance cost [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	23 years
Regulatory assets	3,276	[1]	3,419	[1]
Renewable energy standard adjustment [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	5 years
Regulatory assets	9,622	[1]	14,186	[1]
Flow through accounting [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	35 years
Regulatory assets	25,887	[2]	20,916	[2]
Decommissioning costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	10 years
Regulatory assets	12,484		0
Other regulatory assets [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	15 years
Regulatory assets	$12,454	[1]	$10,546	[1]
[1]	Recovery of costs, but we are not allowed a rate of return.
[2]	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.
[3]	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. Increases in the current year balances as of December 31, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. 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.
[4]	In addition to recovery of costs, we are allowed a rate of return.
[5]	Increases are due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

Business_Description_And_Signi9

Business Description And Significant Accounting Policies: Earnings per Share (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Income (loss) from continuing operations	$34,007	$26,836	$19,820	$48,118	$19,007	[1],[2]	$23,124	[1]	$30,518	[1]	$43,197	[1]	$128,781	$115,846	$88,505
Weighted average shares - Basic													44,394	44,163	43,820
Dilutive effect of:
Equity compensation													204	256	250
Other diluted effects, shares													0	0	3
Weighted average shares - diluted													44,598	44,419	44,073
Income (loss) from continuing operations - Diluted (usd per share)					$0.43		$0.52		$0.69		$0.97		$2.89	$2.61	$2.01
[1]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
[2]	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.

Recovered_Sheet1

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	81	22	163
Equity Compensation [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	81	22	163

Property_Plant_And_Equipment_P1

Property, Plant And Equipment: Property, Plant and Equipment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	4,563,400		4,259,445
Less: accumulated depreciation, depletion and amortization	1,324,025		1,269,148
Total property, plant and equipment, net	3,239,375		2,990,297
Corporate, Non-Segment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	5,524		5,498
Construction in progress, gross	5,196		5,647
Property, plant and equipment, gross	10,720		11,145
Total property, plant and equipment, net	14,205		14,355
Corporate, Non-Segment [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	11 years		6 years
Corporate, Non-Segment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	5 years		2 years
Corporate, Non-Segment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years		30 years
Intercompany Eliminations [Member]
Property, Plant and Equipment [Line Items]
Less: accumulated depreciation, depletion and amortization	-3,485	[1]	-3,210	[1]
Electric Utilities [Member]
Property, Plant and Equipment [Line Items]
Production	1,125,845		951,138
Transmission	284,032		238,542
Distribution	718,342		666,589
Plant acquisition adjustment	4,870	[2]	4,870	[2]
General	152,982		138,263
Capital lease - plant in service	261,441	[3]	261,441	[3]
Total plant in service before construction work in progress	2,547,512		2,260,843
Construction work in progress	49,700		203,760
Property, plant and equipment, gross	2,597,212	[4]	2,464,603	[4]
Less: accumulated depreciation, depletion and amortization	484,406		472,970
Total property, plant and equipment, net	2,112,806		1,991,633
Depreciation, depletion and amortization, remaining amortization period	16 years
Electric Utilities [Member] | Weighted Average [Member] | Production, Electric [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	45 years		45 years
Electric Utilities [Member] | Weighted Average [Member] | Electric transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	49 years		50 years
Electric Utilities [Member] | Weighted Average [Member] | Electric distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	44 years		44 years
Electric Utilities [Member] | Weighted Average [Member] | Plant acquisition adjustment [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years		32 years
Electric Utilities [Member] | Weighted Average [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	21 years		22 years
Electric Utilities [Member] | Weighted Average [Member] | Assets Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years		20 years
Electric Utilities [Member] | Minimum [Member] | Production, Electric [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	25 years
Electric Utilities [Member] | Minimum [Member] | Electric transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years
Electric Utilities [Member] | Minimum [Member] | Electric distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years
Electric Utilities [Member] | Minimum [Member] | Plant acquisition adjustment [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities [Member] | Minimum [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years
Electric Utilities [Member] | Minimum [Member] | Assets Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Electric Utilities [Member] | Maximum [Member] | Production, Electric [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	65 years
Electric Utilities [Member] | Maximum [Member] | Electric transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	65 years
Electric Utilities [Member] | Maximum [Member] | Electric distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	65 years
Electric Utilities [Member] | Maximum [Member] | Plant acquisition adjustment [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities [Member] | Maximum [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	60 years
Electric Utilities [Member] | Maximum [Member] | Assets Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Gas Utilities [Member]
Property, Plant and Equipment [Line Items]
Production	13		13
Transmission	24,090		24,984
Distribution	557,405		507,318
General	90,085		85,841
Total plant in service before construction work in progress	671,593		618,156
Construction work in progress	16,072		9,417
Property, plant and equipment, gross	687,665		627,573
Less: accumulated depreciation, depletion and amortization	92,035		84,679
Total property, plant and equipment, net	595,630		542,894
Gas Utilities [Member] | Weighted Average [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	19 years		19 years
Gas Utilities [Member] | Weighted Average [Member] | Production, Gas [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	37 years		37 years
Gas Utilities [Member] | Weighted Average [Member] | Gas transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	54 years		54 years
Gas Utilities [Member] | Weighted Average [Member] | Gas distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	46 years		46 years
Gas Utilities [Member] | Minimum [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	16 years
Gas Utilities [Member] | Minimum [Member] | Production, Gas [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	37 years
Gas Utilities [Member] | Minimum [Member] | Gas transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	53 years
Gas Utilities [Member] | Minimum [Member] | Gas distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	41 years
Gas Utilities [Member] | Maximum [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	22 years
Gas Utilities [Member] | Maximum [Member] | Production, Gas [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	37 years
Gas Utilities [Member] | Maximum [Member] | Gas transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	57 years
Gas Utilities [Member] | Maximum [Member] | Gas distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	56 years
Power Generation [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	153,779		143,026
Construction in progress, gross	2,262		10,491
Property, plant and equipment, gross	156,041	[4]	153,517	[4]
Less: accumulated depreciation, depletion and amortization	47,704		43,069
Total property, plant and equipment, net	108,337		110,448
Power Generation [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years		36 years
Power Generation [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years		2 years
Power Generation [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years		40 years
Coal Mining [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	145,619		149,067
Construction in progress, gross	3,748		1,156
Property, plant and equipment, gross	149,367		150,223
Less: accumulated depreciation, depletion and amortization	90,629		86,306
Total property, plant and equipment, net	58,738		63,917
Coal Mining [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years		14 years
Coal Mining [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years		2 years
Coal Mining [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	59 years		59 years
Oil and Gas [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	962,395		852,384
Construction in progress, gross	0		0
Property, plant and equipment, gross	962,395		852,384
Less: accumulated depreciation, depletion and amortization	612,736		585,334
Total property, plant and equipment, net	349,659		267,050
Oil and Gas [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	24 years		24 years
Oil and Gas [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years		3 years
Oil and Gas [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life	25 years		25 years
Non Regulated Energy Group [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,261,793		1,144,477
Construction in progress, gross	6,010		11,647
Property, plant and equipment, gross	1,267,803		1,156,124
Less: accumulated depreciation, depletion and amortization	751,069		714,709
Total property, plant and equipment, net	516,734		441,415
[1]	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.
[2]	The plant acquisition adjustment is included in rate base and is being recovered with 16 years remaining.
[3]	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.
[4]	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.

Jointly_Owned_Facilities_Detai

Jointly Owned Facilities (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Electric Utilities [Member] | Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	20.00%
Ownership Amount of Plant in Service	$110,123
Ownership Amount of Construction Work in Progress	1,201
Ownership Amount of Plant Accumulated Depreciation	53,816
Electric Utilities [Member] | Transmission Tie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	35.00%
Ownership Amount of Plant in Service	19,648
Ownership Amount of Construction Work in Progress	0
Ownership Amount of Plant Accumulated Depreciation	4,976
Electric Utilities [Member] | Wygen I I I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	52.00%
Ownership Amount of Plant in Service	136,220
Ownership Amount of Construction Work in Progress	29
Ownership Amount of Plant Accumulated Depreciation	13,811
Electric Utilities [Member] | Busch Ranch Wind Farm [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	50.00%
Ownership Amount of Plant in Service	18,590
Ownership Amount of Construction Work in Progress	0
Ownership Amount of Plant Accumulated Depreciation	1,573
Power Generation [Member] | Wygen I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	76.50%
Ownership Amount of Plant in Service	109,040
Ownership Amount of Construction Work in Progress	1,765
Ownership Amount of Plant Accumulated Depreciation	$31,852

Business_Segments_Information_1

Business Segments Information: Segment Assets (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Segment Reporting, Asset Reconciling Item
Total Assets	$4,279,806		$3,875,178
Corporate, Non-Segment [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	106,605		80,731
Electric Utilities [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	2,748,680	[1]	2,525,947	[1]
Gas Utilities [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	906,922		805,617
Power Generation [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	76,945	[1]	95,692	[1]
Coal Mining [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	74,407		78,825
Oil and Gas [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	$366,247		$288,366
[1]	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.

Business_Segments_Information_2

Business Segments Information: Capital Expenditures and Asset Acquisitions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	$391,267	[1]	$379,534	[1]
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	9,046	[1]	10,319	[1]
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	193,199	[1]	222,262	[1]
Gas Utilities [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	70,528	[1]	63,205	[1]
Power Generation [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	2,379	[1]	13,533	[1]
Coal Mining [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	6,676	[1]	5,528	[1]
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	$109,439	[1]	$64,687	[1]
[1]	Includes accruals for property, plant and equipment.

Business_Segments_Information_3

Business Segments Information: Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	$4,563,400		$4,259,445
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	10,720		11,145
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	2,597,212	[1]	2,464,603	[1]
Gas Utilities [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	687,665		627,573
Power Generation [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	156,041	[1]	153,517	[1]
Coal Mining [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	149,367		150,223
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	$962,395		$852,384
[1]	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.

Business_Segments_Information_4

Business Segments Information: Information Relating to Segments Statement of Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information
Revenue	$378,077	$272,087	$283,237	$460,169	$355,448	$259,907	$279,826	$380,671	$1,393,570	$1,275,852		$1,173,884
Fuel, purchased power and cost of natural gas sold									581,782	492,147		407,066
Operations and maintenance									403,175	386,936		370,736
Gain on sale of operating assets									0	0		-29,129	[1]
Depreciation, depletion and amortization									148,083	141,217		154,632
Impairment of long-lived assets									0	0		26,868	[2]
Operating income	69,951	54,404	46,577	89,598	71,103	55,566	49,037	79,846	260,530	255,552		243,711
Interest expense									-70,960	-111,788	[3]	-113,610	[4]
Unrealized gain (loss) on interest rate swaps, net									0	30,169		1,882
Interest income									1,925	1,723		1,957
Other income (expense), net									2,681	1,798		2,965
Income tax benefit (expense)									-65,395	-61,608		-48,400
Income (loss) from continuing operations									128,781	115,846		88,505
Electric Utilities [Member]
Segment Reporting Information
Revenue									683,201	651,445		610,732
Fuel, purchased power and cost of natural gas sold									314,573	294,048		273,474
Operations and maintenance									165,641	159,961		146,527
Gain on sale of operating assets												0
Depreciation, depletion and amortization									79,424	77,704		75,244
Impairment of long-lived assets												0
Operating income									137,673	133,595		131,721
Interest expense									-53,402	-61,537		-59,194
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									4,615	5,277		8,153
Other income (expense), net									1,164	633		1,182
Income tax benefit (expense)									-30,498	-25,834		-30,264
Income (loss) from continuing operations									59,552	52,134		51,598
Gas Utilities [Member]
Segment Reporting Information
Revenue									617,768	539,689		454,081
Fuel, purchased power and cost of natural gas sold									380,852	310,463		245,349
Operations and maintenance									132,635	126,073		117,390
Gain on sale of operating assets												0
Depreciation, depletion and amortization									26,499	26,381		25,163
Impairment of long-lived assets												0
Operating income									77,782	76,772		66,179
Interest expense									-15,725	-25,234		-26,746
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									441	976		2,765
Other income (expense), net									34	-60		105
Income tax benefit (expense)									-20,663	-19,747		-14,313
Income (loss) from continuing operations									41,869	32,707		27,990
Power Generation [Member]
Segment Reporting Information
Revenue									6,401	4,648		4,189
Fuel, purchased power and cost of natural gas sold									0	0		0
Operations and maintenance									33,126	30,186		29,991
Gain on sale of operating assets												0
Depreciation, depletion and amortization									4,540	5,091		4,599
Impairment of long-lived assets												0
Operating income									49,892	47,760		44,799
Interest expense									-4,351	-21,178	[3]	-15,452
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									682	785		695
Other income (expense), net									-6	1		7
Income tax benefit (expense)									-17,701	-11,080		-8,721
Income (loss) from continuing operations									28,516	16,288		21,328
Coal Mining [Member]
Segment Reporting Information
Revenue									31,086	25,186		25,810
Fuel, purchased power and cost of natural gas sold									0	0		0
Operations and maintenance									41,172	39,519		42,553
Gain on sale of operating assets												0
Depreciation, depletion and amortization									10,276	11,523		13,060
Impairment of long-lived assets												0
Operating income									11,910	5,586		2,165
Interest expense									-493	-641		-238
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									59	10		1,168
Other income (expense), net									2,275	2,304		2,616
Income tax benefit (expense)									-3,299	-932		-85
Income (loss) from continuing operations									10,452	6,327		5,626
Oil and Gas [Member]
Segment Reporting Information
Revenue									55,114	54,884		79,072
Fuel, purchased power and cost of natural gas sold									0	0		0
Operations and maintenance									42,659	40,365		43,267
Gain on sale of operating assets												-29,129	[1]
Depreciation, depletion and amortization									27,584	21,770		38,494
Impairment of long-lived assets												26,868	[2]
Operating income									-15,129	-7,251		-428
Interest expense									-2,603	-2,253		-4,539
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									918	1,639		604
Other income (expense), net									183	108		207
Income tax benefit (expense)									5,998	3,545		1,927
Income (loss) from continuing operations									-10,633	-4,212		-2,229
Intercompany Eliminations [Member]
Segment Reporting Information
Revenue									-349,999	-344,314		-319,855
Fuel, purchased power and cost of natural gas sold									-113,759	-112,489		-111,757
Operations and maintenance									-225,473	-211,977		-188,051
Gain on sale of operating assets												0
Depreciation, depletion and amortization									-7,930	-12,876		-12,864
Impairment of long-lived assets												0
Operating income									-2,837	-6,972		-7,183
Interest expense									55,913	84,250		85,209
Unrealized gain (loss) on interest rate swaps, net										0		0
Interest income									-53,759	-76,724		-76,123
Other income (expense), net									-62,574	-42,641		-49,921
Income tax benefit (expense)									744	218		-131
Income (loss) from continuing operations									-62,513	-41,869		-48,149
Intercompany Eliminations [Member] | Electric Utilities [Member]
Segment Reporting Information
Revenue									14,110	13,863		16,234
Intercompany Eliminations [Member] | Gas Utilities [Member]
Segment Reporting Information
Revenue									0	0		0
Intercompany Eliminations [Member] | Power Generation [Member]
Segment Reporting Information
Revenue									81,157	78,389		75,200
Intercompany Eliminations [Member] | Coal Mining [Member]
Segment Reporting Information
Revenue									32,272	31,442		31,968
Intercompany Eliminations [Member] | Oil and Gas [Member]
Segment Reporting Information
Revenue									0	0		0
Operating Segments [Member] | Electric Utilities [Member]
Segment Reporting Information
Revenue									697,311	665,308		626,966
Operating Segments [Member] | Gas Utilities [Member]
Segment Reporting Information
Revenue									617,768	539,689		454,081
Operating Segments [Member] | Power Generation [Member]
Segment Reporting Information
Revenue									87,558	83,037		79,389
Operating Segments [Member] | Coal Mining [Member]
Segment Reporting Information
Revenue									63,358	56,628		57,778
Operating Segments [Member] | Oil and Gas [Member]
Segment Reporting Information
Revenue									55,114	54,884		79,072
Corporate, Non-Segment [Member]
Segment Reporting Information
Revenue									222,460	220,620		196,453
Fuel, purchased power and cost of natural gas sold									116	125		0
Operations and maintenance									213,415	202,809		179,059
Gain on sale of operating assets												0
Depreciation, depletion and amortization									7,690	11,624		10,936
Impairment of long-lived assets												0
Operating income									1,239	6,062		6,458
Interest expense									-50,299	-85,195	[3]	-92,650	[4]
Unrealized gain (loss) on interest rate swaps, net										30,169		1,882
Interest income									48,969	69,760		64,695
Other income (expense), net									61,605	41,453		48,769
Income tax benefit (expense)									24	-7,778		3,187
Income (loss) from continuing operations									61,538	54,471		32,341
Consolidation, Eliminations [Member]
Segment Reporting Information
Revenue									$0	$0		$0
[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Oil and Gas includes a ceiling test impairment (see Note 12).
[3]	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).
[4]	Corporate includes a make-whole provision from early repayment of long-term debt.

LongTerm_Debt_LongTerm_Debt_De

Long-Term Debt: Long-Term Debt (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Oct. 01, 2014	Nov. 19, 2013	Jun. 21, 2013
Debt Instrument [Line Items]
Long-term Debt, including current maturities	$1,542,589		$1,396,948
Long-term Debt, Current Maturities	-275,000		0
Long-term debt, net of current maturities	1,267,589		1,396,948
First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt, Fixed Interest Rate	4.43%
Long-term Debt	85,000				160,000
Polution Control Revenue Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Fixed Interest Rate	5.35%
Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt	544,753		396,948
Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	15-Aug-32
Long-term Debt, Fixed Interest Rate	7.23%
Long-term Debt	75,000		75,000
Electric Utilities [Member] | First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	1-Nov-39
Long-term Debt, Fixed Interest Rate	6.13%
Long-term Debt	180,000		180,000
Debt Instrument, Unamortized Discount	-102		-107
Electric Utilities [Member] | Polution Control Revenue Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	1-Oct-24
Long-term Debt, Fixed Interest Rate	5.35%
Long-term Debt	0		12,200
Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	20-Nov-37
Long-term Debt, Fixed Interest Rate	6.67%
Long-term Debt	110,000		110,000
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	1-Sep-21
Long-term Debt, Variable Interest Rate	0.09%	[1]
Long-term Debt	7,000	[1]	7,000	[1]
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	1-Mar-27
Long-term Debt, Variable Interest Rate	0.09%	[1]
Long-term Debt	10,000	[1]	10,000	[1]
Electric Utilities [Member] | Series 94 A Debt, Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	1-Jun-24
Long-term Debt, Variable Interest Rate	0.75%	[1]
Long-term Debt	2,855	[1]	2,855	[1]
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt	997,836		1,000,000
Black Hills Corporation [Member] | Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	30-Nov-23
Long-term Debt, Fixed Interest Rate	4.25%
Long-term Debt	525,000		525,000			525,000
Debt Instrument, Unamortized Discount	-2,164	[2]	0	[2]
Black Hills Corporation [Member] | Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	15-Jul-20
Long-term Debt, Fixed Interest Rate	5.88%
Long-term Debt	200,000		200,000
Black Hills Power [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	20-Oct-44
Long-term Debt, Fixed Interest Rate	4.43%
Long-term Debt	85,000		0
Cheyenne Light [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	20-Oct-44
Long-term Debt, Fixed Interest Rate	4.53%
Long-term Debt	75,000		0		75,000
London Interbank Offered Rate (LIBOR) [Member] | Black Hills Corporation [Member] | Corporate Term Loan due June 2015 [Member] [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	19-Jun-15		19-Jun-15
Long-term Debt, Variable Interest Rate	1.31%	[3]
Long-term Debt	$275,000		$275,000				$275,000
[1]	Variable interest rate.
[2]	Discount on note initially reflected in deferred financing costs at December 31, 2013.
[3]	Variable interest rate, based on LIBOR plus a spread.

LongTerm_Debt_Aggregate_Maturi

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Long-term Debt, Unclassified [Abstract]
2015	$275,000	$0
2016	0
2017	0
2018	0
2019	0
After 2019	$1,269,855

LongTerm_Debt_Debt_Transaction

Long-Term Debt: Debt Transactions (Details) (USD $)	12 Months Ended				0 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Nov. 19, 2013	Jun. 21, 2013	Dec. 19, 2013	Oct. 01, 2014
Debt Instrument [Line Items]
Derivative Liability	$6,020,000		$9,088,000
Repayments of Lines of Credit	403,750,000		532,150,000	271,753,000
Loans Payable [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			150,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Repayments of Lines of Credit					55,000,000	25,000,000
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Notional Amount					250,000,000
Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt	544,753,000		396,948,000
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt	997,836,000		1,000,000,000
Black Hills Corporation [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Debt Instrument [Line Items]
Derivative Liability					64,000,000
First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	85,000,000							160,000,000
Long-term Debt, Fixed Interest Rate	4.43%
First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member] | Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt	85,000,000		0
Long-term Debt, Fixed Interest Rate	4.43%
Long-term Debt, Maturity Date	20-Oct-44
First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member] | Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt	75,000,000		0					75,000,000
Long-term Debt, Fixed Interest Rate	4.53%
Long-term Debt, Maturity Date	20-Oct-44
Polution Control Revenue Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Fixed Interest Rate	5.35%
Extinguishment of Debt, Amount	12,000,000
Polution Control Revenue Bonds Due 2024 [Member] | Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt	0		12,200,000
Long-term Debt, Fixed Interest Rate	5.35%
Long-term Debt, Maturity Date	1-Oct-24
Senior Unsecured Notes Due 2023 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt	525,000,000		525,000,000		525,000,000
Long-term Debt, Fixed Interest Rate	4.25%
Long-term Debt, Maturity Date	30-Nov-23
Senior Unsecured Notes Due 2014 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt, Fixed Interest Rate			9.00%
Extinguishment of Debt, Amount			250,000,000
Long-term Debt, Maturity Date			15-May-14
Early Repayment of Senior Debt							261,000,000
Interest Expense, Prepayment of Debt							8,500,000
Project Financing Debt Due 2016 [Member] | Power Generation [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount					87,000,000
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net					8,500,000
Corporate Term Loan due June 2015 [Member] [Member] | Black Hills Corporation [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt	275,000,000		275,000,000			275,000,000
Long-term Debt, Maturity Date	19-Jun-15		19-Jun-15
Long-term Debt, Variable Interest Rate	1.31%	[1]
Debt Instrument, Basis Spread on Variable Rate	1.13%
Corporate Term Loan due September 2013 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			$100,000,000
[1]	Variable interest rate, based on LIBOR plus a spread.

LongTerm_Debt_Deferred_Financi

Long-Term Debt: Deferred Financing Costs (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$3,908
Amortization Expense for Deferred Financing Costs	653		86		0
Senior Unsecured Notes Due 2014 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	0
Amortization Expense for Deferred Financing Costs	0		635		462
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	926
Amortization Expense for Deferred Financing Costs	167		167		167
First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	584
Amortization Expense for Deferred Financing Costs	33		33		33
First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,885
Amortization Expense for Deferred Financing Costs	76		76		76
First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	705
Amortization Expense for Deferred Financing Costs	31		31		31
Project Financing Debt Due 2016 [Member]
Debt Instrument [Line Items]
Amortization Expense for Deferred Financing Costs	0		3,177	[1]	1,037
Deferred Financing Costs, Other [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	483
Amortization Expense for Deferred Financing Costs	53		57		57
Black Hills Power [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	711
Amortization Expense for Deferred Financing Costs	6	[2]	0		0
Cheyenne Light [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	654
Amortization Expense for Deferred Financing Costs	$6	[2]	$0		$0
[1]	This project financing was repaid in 2013 and the deferred financing costs were written off.
[2]	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.

LongTerm_Debt_Dividend_Restric

Long-Term Debt: Dividend Restrictions (Details) (Utilities Group [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Utilities Group [Member]
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$315

Notes_Payable_Notes_Payable_De

Notes Payable: Notes Payable (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revolving Credit Facility [Line Items]
Balance Outstanding	$75,000,000	$82,500,000
Deferred Finance Costs [Abstract]
Write off of Deferred Debt Issuance Cost			1,500,000
Revolving Credit Facility [Member]
Revolving Credit Facility [Line Items]
Balance Outstanding	75,000,000	82,500,000
Current Borrowing Capacity	500,000,000
Expiration Date	29-May-19
Maximum Borrowing Capacity	750,000,000
Commitment Fee Percentage	0.18%
Commitment Fee Percentage Decrease	0.03%
Letters of Credit Outstanding	35,000,000	22,000,000
Deferred Finance Costs [Abstract]
Deferred Finance Costs, Noncurrent, Gross	3,800,000
Deferred Finance Costs, Noncurrent, Net	1,779,000
Amortization Expense for Deferred Financing Costs	$616,000	$752,000	$2,187,000
Debt Covenants Disclosure [Abstract]
Covenant Requirement - Recourse Leverage Ratio, Actual	55.00%
Covenant Requirement - Recourse Leverage Ratio, Maximum	65.00%
Revolving Credit Facility [Member] | Base Rate Borrowings [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	0.13%
Interest Rate Decrease	0.25%
Revolving Credit Facility [Member] | Eurodollar Borrowings [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.13%
Interest Rate Decrease	0.25%
Revolving Credit Facility [Member] | Letters of Credit [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.13%
Interest Rate Decrease	0.25%

Asset_Retirement_Obligations_A1

Asset Retirement Obligations: Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,	$51,851		$50,548
Liabilities Incurred	413		146
Liabilities Settled	-1,017		-2,617
Accretion Expense	2,186		2,685
Revision of Prior Estimate	-6,047	[1],[2]	1,089
Balance on December 31,	47,386		51,851
Electric Utilities [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,	6,922		6,981
Liabilities Incurred	0		0
Liabilities Settled	-85		0
Accretion Expense	175		168
Revision of Prior Estimate	0		-227
Balance on December 31,	7,012		6,922
Gas Utilities [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,	274		259
Liabilities Incurred	0		0
Liabilities Settled	0		0
Accretion Expense	17		15
Revision of Prior Estimate	0		0
Balance on December 31,	291		274
Coal Mining [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,	20,627		20,286
Liabilities Incurred	345		3
Liabilities Settled	0		-714
Accretion Expense	951		1,052
Revision of Prior Estimate	-2,785	[1]	0
Balance on December 31,	19,138		20,627
Oil and Gas [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,	24,028		23,022
Liabilities Incurred	68		143
Liabilities Settled	-932		-1,903
Accretion Expense	1,043		1,450
Revision of Prior Estimate	-3,262	[2]	1,316
Balance on December 31,	$20,945		$24,028
[1]	The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability.
[2]	The Oil and Gas Revision to Prior Estimates was due to a change in useful well lives used in calculating the estimated liability.

Risk_Management_Activities_Ris1

Risk Management Activities: Risk Management Activities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Derivative assets, current	0		717,000
Derivative assets, non-current	0		0
Derivative liabilities, current	3,340,000		3,474,000
Derivative liabilities, non-current	2,680,000		5,614,000
Oil and Gas [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	10,000,000
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Maximum Term	2 years		3 years
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative liabilities, current	3,340,000		3,474,000
Derivative liabilities, non-current	2,680,000		5,614,000
Notional Amount	75,000,000	[1]	75,000,000	[1]
Weighted average fixed interest rate	4.97%		4.97%
Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	3,300,000
Crude Oil [Member] | Swaps and Options [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities	334,500	[2]	412,500	[2]
MaximumTerm Hedged in Cash Flow Hedge	1 month	[3]	3 months	[3]
Derivative assets, current	0		55,000
Derivative assets, non-current	0		0
Derivative liabilities, current	0		0
Derivative liabilities, non-current	0		0
Natural Gas [Member] | Swap [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities	6,582,500	[2]	7,082,500	[2]
MaximumTerm Hedged in Cash Flow Hedge	1 month	[3]	1 month	[3]
Derivative assets, current	0		0
Derivative assets, non-current	0		0
Derivative liabilities, current	0		0
Derivative liabilities, non-current	0		0
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Credit Exposure, Non-investment Grade Company	600,000
Utilities Group [Member] | Natural Gas, Distribution [Member]
Derivative [Line Items]
Derivative assets, current	0		662,000
Derivative assets, non-current	0		0
Derivative liabilities, current	0		0
Derivative liabilities, non-current	0		0
Net Unrealized Gain (Loss) Included in Regulatory assets or Regulatory liabilities	18,740,000		7,567,000
Utilities Group [Member] | Natural Gas, Distribution [Member] | Future [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities	19,370,000		17,930,000
Maximum Term	72 months	[4]	84 months	[4]
Utilities Group [Member] | Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities	4,020,000		3,890,000
Maximum Term	8 months	[4]	8 months	[4]
Utilities Group [Member] | Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities	12,005,000		14,785,000
Maximum Term	60 months	[4]	60 months	[4]
[1]	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related borrowings.
[2]	Crude in Bbls, gas in MMBtu.
[3]	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
[4]	Term reflects the maximum forward period hedged.

Risk_Management_Activities_Hed

Risk Management Activities: Hedging Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$0	$17,267		($11,077)
Cash Flow Hedging [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	14,145	6,979		-2,155
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	5,664	6,062		1,177
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0		0
Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	-536	7,935		-4,794
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0		0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	3,669	6,989		-7,607
Cash Flow Hedging [Member] | Commodity derivatives [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	14,681	-956		2,639
Cash Flow Hedging [Member] | Commodity derivatives [Member] | Sales Revenue, Goods, Net [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	1,995	-927		8,784
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0		0
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Unrealized Gain Loss on Interest Rate Swaps [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	0	30,169	[1]	1,882
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$0	($12,902)	[1]	($12,959)
[1]	These interest rate swaps were settled in the fourth quarter of 2013.

Fair_Value_Measurements_Fair_V1

Fair Value Measurements: Fair Value Measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	$0	$717
Derivative, Liabilities, Fair Value Disclosure	6,020	9,088
Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]
Assets-Transfers out of level 1 to 2	0	0
Assets -Transfers out of level 2 to 1	0	0
Liabilities -Transfers out of level 1 to 2	0	0
Liabilities -Transfers out of level 2 to 1	0	0
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-17,546	-3,258
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-19,776	-10,860
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	17,546	3,975
Derivative Liabilities, Total	25,796	19,948
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	6,020	9,088
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	6,020	9,088
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-8,599	-75
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	-1,229
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	8,599	130
Derivative, Liabilities, Fair Value Disclosure	0	1,229
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-6,558	-815
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-473	-531
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	6,558	815
Derivative, Liabilities, Fair Value Disclosure	473	531
Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	-2,389	-2,368
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	-19,303	-9,100
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	2,389	3,030
Derivative, Liabilities, Fair Value Disclosure	19,303	9,100
Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	717
Derivative Liabilities, Total	6,020	9,088
Estimate of Fair Value Measurement [Member] | Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	55
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas, Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	662
Derivative, Liabilities, Fair Value Disclosure	$0	$0

Fair_Value_Measurements_Balanc

Fair Value Measurements: Balance Sheet Location (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$17,546	$3,975
Derivative Liability, Fair Value, Gross Liability	25,796	19,948
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	15,157	946
Derivative Liability, Fair Value, Net	6,493	10,848
Derivatives Not Designated as Hedge Instruments [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	0	662
Derivative Liability, Fair Value, Net	16,914	6,732
Commodity derivatives [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,391	248
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,766	698
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	185	1,541
Commodity derivatives [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	288	219
Commodity derivatives [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	662
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Assets, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	8,032	0
Commodity derivatives [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	8,882	6,732
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	3,340	3,474
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	2,680	5,614
Interest Rate Swap [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Liabilities, Current [Member]
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 [Member] | Derivatives Not Designated as Hedge Instruments [Member] | Derivative Liabilities, Noncurrent [Member]
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_Balanc1

Fair Value Measurements: Balance Sheet Offsetting (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$17,546	$3,975
Gross Amounts Offset In Statement Of Financial Position Assets	-17,546	-3,258
Derivative Asset	0	717
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	25,796	19,948
Gross Amounts Offset In Statement Of Financial Position Liabilities	-19,776	-10,860
Derivative Liability	6,020	9,088
Contract Subject to Master Netting Arrangement [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	17,546	3,920
Gross Amounts Offset In Statement Of Financial Position Assets	-17,546	-3,258
Derivative Asset	0	662
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	19,776	10,860
Gross Amounts Offset In Statement Of Financial Position Liabilities	-19,776	-10,860
Derivative Liability	0	0
Contract Subject to Master Netting Arrangement [Member] | Interest Rate Swap [Member]
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Contract Not Subject to Master Netting Arrangement [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	55
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	55
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	6,020	9,088
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	6,020	9,088
Contract Not Subject to Master Netting Arrangement [Member] | Interest Rate Swap [Member]
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	6,020	9,088
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	6,020	9,088
Crude Oil [Member] | Contract Subject to Master Netting Arrangement [Member] | Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	8,599	75
Gross Amounts Offset In Statement Of Financial Position Assets	-8,599	-75
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	1,229
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	-1,229
Derivative Liability	0	0
Crude Oil [Member] | Contract Subject to Master Netting Arrangement [Member] | Commodity Option [Member]
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	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Crude Oil [Member] | Contract Not Subject to Master Netting Arrangement [Member] | Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0	55
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	0	55
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Crude Oil [Member] | Contract Not Subject to Master Netting Arrangement [Member] | Commodity Option [Member]
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	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Natural Gas [Member] | Contract Subject to Master Netting Arrangement [Member] | Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	6,558	815
Gross Amounts Offset In Statement Of Financial Position Assets	-6,558	-815
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	473	531
Gross Amounts Offset In Statement Of Financial Position Liabilities	-473	-531
Derivative Liability	0	0
Natural Gas [Member] | Contract Not Subject to Master Netting Arrangement [Member] | Basis Swap [Member]
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	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	0
Natural Gas, Distribution [Member] | Contract Subject to Master Netting Arrangement [Member] | Purchase Contract [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	2,389	3,030
Gross Amounts Offset In Statement Of Financial Position Assets	-2,389	-2,368
Derivative Asset	0	662
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	19,303	9,100
Gross Amounts Offset In Statement Of Financial Position Liabilities	-19,303	-9,100
Derivative Liability	0	0
Natural Gas, Distribution [Member] | Contract Not Subject to Master Netting Arrangement [Member] | Purchase Contract [Member]
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	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	$0	$0

Fair_Value_Measurements_Balanc2

Fair Value Measurements: Balance Sheet Offsetting by Counterparty (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Asset [Abstract]
Derivative Asset	$0	$717
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	0	717
Derivative Liability [Abstract]
Derivative Liability	6,020	9,088
Derivative, Collateral, Right to Reclaim Cash	-7,485	-5,021
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	-1,465	4,067
Counterparty F [Member]
Derivative Liability [Abstract]
Derivative Liability	6,020	9,088
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	6,020	9,088
Utilities Group [Member] | Counterparty A [Member]
Derivative Asset [Abstract]
Derivative Asset	0	662
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	0	662
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	-3,093	-3,390
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	-3,093	-3,390
Oil and Gas [Member] | Counterparty A [Member]
Derivative Asset [Abstract]
Derivative Asset	0	0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	0	0
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	-4,392	-1,631
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	-4,392	-1,631
Oil and Gas [Member] | Counterparty B [Member]
Derivative Asset [Abstract]
Derivative Asset	0	55
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Withing Derivative Assets	0	55
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	$0	$0

Fair_Value_Of_Financial_Instru2

Fair Value Of Financial Instruments: Fair Value of Financial Instruments (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	$21,218		$7,841
Restricted cash - carrying amount	2,056		2
Notes payable	75,000		82,500
Long-term debt, including current maturities - carrying amount	1,542,589		1,396,948
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	21,218		7,841
Restricted cash - carrying amount	2,056		2
Notes payable	75,000		82,500
Long-term debt, including current maturities - carrying amount	1,542,589		1,396,948
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - fair value	21,218	[1]	7,841	[1]
Restricted Cash - fair value	2,056	[1]	2	[1]
Notes payable - fair value	75,000	[1]	82,500	[1]
Long-term debt, including current maturities - fair value	$1,734,555	[2]	$1,491,422	[2]
[1]	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.
[2]	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

Stock_Equity_Compensation_Plan

Stock: Equity Compensation Plans Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Shares available for grant	522,831
Unrecognized compensation expense	$9,400,000
Weighted-average recognition period	1 year 7 months
Stock-based compensation expense	$9,329,000	$12,595,000	$8,271,000

Stock_Stock_Option_Activity_De

Stock: Stock Option Activity (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Weighted-average recognition period	1 year 7 months
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Stock option award, effective term	10 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Options, Shares - Beginning	61
Granted	81	[1]
Forfeited/canceled	0
Expired	0
Exercised	-8
Options, Shares - Ending	134		61
Exercisable at end of period	46
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Outstanding (usd per share) (Beginning)	$33.25
Granted (usd per share)	$54.29	[1]
Forfeited/canceled (usd per share)	$0
Expired (usd per share)	$0
Exercised (usd per share)	$30.87
Options, Outstanding (usd per share) (Ending)	$46.12		$33.25
Exercisable at end of period (usd per share)	$32.63
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Weighted average remaining contractual term	8 years 2 months 6 days
Exercisable at end of period, weighted average remaining contractual term	6 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Options, aggregate intrinsic value	$1,027
Exercisable at end of period, aggregate intrinsic value	944
Grant date fair value of awards (usd per share)	$12.58	[1]
Risk free interest rate assumption	2.10%
Expected price volatility assumption	29.40%
Expected dividend yield assumption	2.90%
Expected term assumption	7 years
Unrecognized compensation expense	816		130		218
Intrinsic value of options exercised	199	[2]	789	[2]	623	[2]
Net cash received from exercise of options	237		2,046		2,839
Tax benefit realized from exercise of shares	$70	[3]	$276	[3]	$218	[3]
Weighted-average recognition period	2 years 1 month
[1]	The grant date fair value of the 2014 awards was $12.58 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.1% risk free interest rate, 29.4% expected price volatility, 2.9% expected dividend yield and a 7 year expected life.
[2]	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
[3]	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

Stock_Restricted_Stock_Details

Stock: Restricted Stock (Details) (USD $)	12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Unrecognized compensation expense	$9,400,000
Weighted-average recognition period	1 year 7 months
Restricted Stock [Member]
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	262
Granted	99
Vested	-114
Forfeited	-14
Restricted Stock at end of period	233	262
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)	$36.76
Granted (usd per share)	$54.34	$40.56	$34.99
Vested (usd per share)	$35.25
Forfeited (usd per share)	$43.17
Balance at end of period (usd per share)	$44.60	$36.76
Restricted Stock and RSUs, total fair value of shares vested	6,114,000	5,842,000	3,781,000
Unrecognized compensation expense	$6,100,000
Weighted-average recognition period	1 year 8 months 12 days

Stock_Performance_Shares_Detai

Stock: Performance Shares (Details) (USD $)	12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$9,400,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Weighted-average recognition period	1 year 7 months
Performance Shares [Member]
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	2,100,000
Performance Share Award, Percentage of Target	200.00%
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	61		64
Performance Shares, Number of Shares Authorized, End of Period	44		61	64
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Granted (usd per share)			$35.85	$32.26
Blended volatility	23.00%		20.00%	21.00%
Historical volatility	50.00%
Implied volatility	50.00%
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	59		63	0
Performance Shares, Total Share-based Liabilities Paid	3,011,000		2,267,000	0
Performance Shares, Vested in Period, Total Intrinsic Value	6,020,000		4,533,000	0
Peer Percentile	1
Target shares, value	7,300,000
Unrecognized compensation expense	$2,500,000
Weighted-average recognition period	1 year 6 months
Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	93
Performance Shares, Granted in Period	23
Performance Shares, Forfeited in Period	-1
Performance Shares, Vested in Period	-31
Performance Shares, Number of Shares Authorized, End of Period	84
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at end of period (usd per share)	$82.42	[1]
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	93
Performance Shares, Granted in Period	23
Performance Shares, Forfeited in Period	-1
Performance Shares, Vested in Period	-31
Performance Shares, Number of Shares Authorized, End of Period	84
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at beginning of period (usd per share)	$31.34	[2]
Granted (usd per share)	$55.18	[2]
Forfeited (usd per share)	$40.12	[2]
Vested (usd per share)	$25.92	[2]
Balance at end of period (usd per share)	$39.58	[2]
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%		0.00%	0.00%
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%		200.00%	200.00%
Maximum [Member] | Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target				200.00%
Performance Period, 2013 To 2015 [Member] | Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target				157.00%
Performance Period, 2014 To 2016 [Member] | Performance Shares, Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target				51.00%
[1]	The weighted-average fair value for the liability portion at December 31, 2014 was determined by the actual performance for the 2012 to 2014 performance period at the top of the peer group resulting in a 200% of target payout, and determined by Monte Carlo simulations for the 2013 to 2015 performance period and 2014 to 2016 performance period projecting a 157% and 51% of target payouts, respectively.
[2]	The grant date fair values for the performance shares granted in 2014, 2013 and 2012 were determined by Monte Carlo simulation using a blended volatility of 23%, 20% and 21%, 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.

Stock_Dividend_Reinvestment_an

Stock: Dividend Reinvestment and Stock Purchase Plan (Details) (Dividend Reinvestment Plan [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Dividend Reinvestment Plan [Member]
Class of Stock [Line Items]
Percent of recent average market price	100.00%
Shares Issued	52,000	67,000
Weighted Average Price	$54.99	$46.78
Unissued Shares Available	474,000	286,000

Stock_Preferred_Stock_Details

Stock: Preferred Stock (Details)	Dec. 31, 2014
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Impairment_Of_LongLived_Assets1

Impairment Of Long-Lived Assets: Impairment of Long-Lived Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Jun. 30, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	$0	$0	$26,868	[1]
Average Natural Gas Price Per MCF, NYMEX	4.35	3.67	2.76
Average Natural Gas Price Per MCF, Wellhead	3.33	3.45	2.24
Average Crude Oil Price, Per Barrel, NYMEX	94.99	96.94	94.71
Average Crude Oil Price Per Barrel, Wellhead	85.8	89.79	85.31
Oil and Gas [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets			$26,868	[1]
Average Natural Gas Price Per MCF, NYMEX					3.15
Average Natural Gas Price Per MCF, Wellhead					2.66
Average Crude Oil Price, Per Barrel, NYMEX					95.67
Average Crude Oil Price Per Barrel, Wellhead					85.36
[1]	Oil and Gas includes a ceiling test impairment (see Note 12).

Operating_Leases_Operating_Lea1

Operating Leases: Operating Lease (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$6,932	$7,169	$6,839
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015	9,962
2016	2,045
2017	1,852
2018	1,829
2019	1,632
Thereafter	$3,735

Income_Taxes_Current_and_Defer

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	($2,319)	($2,003)	$4,972
State	-1,288	-173	3,712
Total Current	-3,607	-2,176	8,684
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	63,645	56,963	39,876
State	5,563	7,033	68
Tax credit amortization	-206	-212	-228
Total Deferred	69,002	63,784	39,716
Total	$65,395	$61,608	$48,400

Income_Taxes_Deferred_Income_T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$49,243		$33,172
Employee benefits	26,714		28,724
Federal net operating loss	213,466		166,095
Asset impairment	55,067		55,124
Other deferred tax assets	76,005	[1]	59,078	[1]
Less: Valuation allowance	-5,017		-1,806
Total deferred tax assets	415,478		340,387
Deferred Tax Liabilities, Net [Abstract]
Accelerated depreciation, amortization and other plant-related differences	-679,911		-598,415
Regulatory assets	-25,340		-24,581
Mining development and oil exploration	-97,198		-69,799
State deferred tax liability	-37,489		-30,293
Deferred costs	-35,284		-15,593
Other deferred tax liabilities	-15,684		-15,104
Total deferred tax liabilities	-890,906		-753,785
Net deferred tax liability	($475,428)		($413,398)
[1]	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.

Income_Taxes_Effective_Tax_Rat

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal Statutory Rate	35.00%		35.00%		35.00%
State Income Tax (net of federal tax effect)	1.10%		2.40%		2.00%
Amortization Of Excess Deferred and Investment Tax Credits	-0.10%		-0.10%		-0.20%
Percentage Depletion In Excess of Cost	-1.00%		-1.00%		-1.30%
Equity AFUDC	-0.10%		0.00%		0.00%
Tax Credits	-0.10%		-0.50%		0.00%
Accounting for Uncertain Tax Positions Adjustment	-0.10%		0.70%		0.80%
Flow Through Adjustments	-0.90%	[1]	-0.90%	[1]	-1.30%	[1]
Other Tax Differences	-0.10%		-0.90%		0.40%
Effective Income Tax Rate, Continuing Operations	33.70%		34.70%		35.40%
[1]	The flow-through adjustments relate 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. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred in 2010. 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 a tax benefit consistent with the flow-through method.

Income_Taxes_Net_Operating_Los

Income Taxes: Net Operating Loss Carryforwards (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$65,395,000	$61,608,000	$48,400,000
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	618,195,000
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	513,418,000
State and Local Jurisdiction [Member] | Valuation Allowance, Operating Loss Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	500,000
Operating Loss Carryforwards Valuation Allowance	1,000,000
Valuation Allowance, Deferred Tax Asset, Change in Amount	$500,000
Minimum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	31-Dec-19
Minimum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	31-Dec-15
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	31-Dec-34
Maximum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	31-Dec-34

Income_Taxes_Reconciliation_of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$37,631,000	$40,683,000	$49,327,000
Additions for prior year tax positions	1,253,000	1,526,000	111,000
Reductions for prior year tax positions	-6,692,000	-4,578,000	-8,906,000
Additions for current year tax positions	0	0	151,000
Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	32,192,000	37,631,000	40,683,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$1,800,000

Income_Taxes_Interest_Penaltie

Income Taxes: Interest, Penalties and Audits (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense	$1,600,000	$1,600,000	$1,400,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	11,500,000	9,900,000
Deferred Income Tax Expense (Benefit)	69,002,000	63,784,000	39,716,000
Like-Kind Exchange, Aquila and IPP Transactions [Member]
Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)	$125,000,000

Income_Taxes_Carryforwards_Sta

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Tax Credit Carryforward [Line Items]
Income Tax Expense (Benefit)	$65,395,000	$61,608,000	$48,400,000
Minimum [Member] | Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	31-Dec-15
Maximum [Member] | Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	31-Dec-17
Foreign Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	500,000
Tax Credit Carryforward, Valuation Allowance	500,000
Internal Revenue Service (IRS) [Member] | Minimum [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2007
Internal Revenue Service (IRS) [Member] | Maximum [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2009
Internal Revenue Service (IRS) [Member] | Settlement with Taxing Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	1,800,000
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	3,500,000
State and Local Jurisdiction [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	14,793,000
State and Local Jurisdiction [Member] | Research Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	155,000
State and Local Jurisdiction [Member] | Deferred Tax Asset [Domain]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	2,700,000
Income Tax Expense (Benefit)	1,500,000
State and Local Jurisdiction [Member] | Deferred Tax Asset [Domain] | Utilities Group [Member]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$1,200,000
State and Local Jurisdiction [Member] | Minimum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	31-Dec-23
State and Local Jurisdiction [Member] | Maximum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	31-Dec-25

Other_Comprehensive_Income_Oth

Other Comprehensive Income: Other Comprehensive Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									$73,017	$113,979	$117,754
Revenue	378,077	272,087	283,237	460,169	355,448	259,907	279,826	380,671	1,393,570	1,275,852	1,173,884
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									194,177	177,540	136,895
Utilities - Operations and maintenance									270,954	261,919	242,367
Non-regulated energy operations and maintenance									88,141	83,762	85,830
Income tax benefit (expense)									-65,395	-61,608	-48,400
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									5,664	6,062
Income tax benefit (expense)									-2,344	-2,016
Net income (loss) available for common stock									3,320	4,046
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									3,669	6,989
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income [Member] | Commodity Contract [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenue									1,995	-927
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Utilities - Operations and maintenance									-102	-125
Non-regulated energy operations and maintenance									-115	-128
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Utilities - Operations and maintenance									630	1,693
Non-regulated energy operations and maintenance									364	1,098
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									777	2,538
Income tax benefit (expense)									-272	-883
Net income (loss) available for common stock									$505	$1,655

Other_Comprehensive_Income_Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	($17,422)	($35,488)
Other comprehensive income (loss), net of tax	2,378	18,066	-2,610
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	-15,044	-17,422	-35,488
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	-6,625	-16,313
Other comprehensive income (loss), net of tax	1,695	9,688
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	-4,930	-6,625
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Commodity Contract [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	-508	600
Other comprehensive income (loss), net of tax	10,531	-1,108
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	10,023	-508
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	-10,289	-19,775
Other comprehensive income (loss), net of tax	-9,848	9,486
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	($20,137)	($10,289)

Supplemental_Disclosure_of_Cas2

Supplemental Disclosure of Cash flow Information: Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$52,584	$59,811	$35,556
Increase (decrease) in capitalized assets associated with asset retirement obligations	-5,634	1,235	5,743
Cash (paid) refunded during the period for continuing operations [Abstract]
Interest (net of amounts capitalized)	-69,239	-108,361	-116,593
Income taxes, net	($413)	($4,573)	($3,027)

Employee_Benefit_Plans_Narrati

Employee Benefit Plans: Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
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
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Measurement Date	31-Dec
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%		7.25%
Pension Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	($78)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%	[1]	7.25%	[1]	7.25%	[1]
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	-41
Other Postretirement Benefit Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	($44)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	2.00%		2.00%		2.00%
Maximum [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Employers Matching Contribution, Annual Vesting Percentage	100.00%
Cheyenne Light [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan Curtailment Effective Date	1-Jan-12
[1]	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.

Employee_Benefit_Plans_Target_

Employee Benefit Plans: Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
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 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	27.00%	26.00%
Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	5.00%	4.00%
Fixed Income Funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	58.00%	58.00%
Cash and Cash Equivalents [Member]
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%	11.00%

Employee_Benefit_Plans_Plan_Co

Employee Benefit Plans: Plan Contributions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$10,000,000
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	10,200,000	12,500,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	3,163,000	5,123,000
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	1,553,000	1,345,000
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	4,187,000	2,775,000
Defined Contribution Plan, 401K [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$9,254,000	$8,524,000

Employee_Benefit_Plans_Employe1

Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Pension Plans, Defined Benefit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$299,533		$280,362		$268,816
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	264,780		242,174
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	34,753		38,188
Pension Plans, Defined Benefit [Member] | 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	541		1,056
Pension Plans, Defined Benefit [Member] | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 1 [Member]
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 [Member] | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	541		1,056
Pension Plans, Defined Benefit [Member] | AXA Equitable General Fixed Income | Fair Value, Inputs, Level 3 [Member]
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 [Member] | 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	4,013		1,253
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,013		1,253
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 3 [Member]
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 [Member] | 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	81,636		73,726
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Equity | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Common Collective Trust - Equity | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	81,636		73,726
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Equity | Fair Value, Inputs, Level 3 [Member]
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 [Member] | 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	174,726		162,747
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	174,726		162,747
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 3 [Member]
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 [Member] | 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	13,583		11,933
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,864		3,392
Pension Plans, Defined Benefit [Member] | Common Collective Trust - Real Estate | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	9,719	[1]	8,541
Pension Plans, Defined Benefit [Member] | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25,034		29,647
Pension Plans, Defined Benefit [Member] | Hedge Funds | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Hedge Funds | Fair Value, Inputs, Level 2 [Member]
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 [Member] | Hedge Funds | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	25,034	[2]	29,647
Other Postretirement Benefit Plans, Defined Benefit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,705	[3]	4,546	[3]	4,351	[3]
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,705		4,546
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
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 [Member] | 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	4,705		4,546
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 1 [Member]
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 [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,705		4,546
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust - Cash and Cash Equivalents | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$0		$0
[1]	The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.
[2]	The fair value of the Hedge Funds is determined based on pricing provided or reviewed by the third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.
[3]	Assets of VEBA

Employee_Benefit_Plans_Changes

Employee Benefit Plans: Changes in Level 3 Assets Measured at Fair Value on a Recurring Basis, Employee Benefits (Details) (Pension Plans, Defined Benefit [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	$299,533		$280,362	$268,816
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	38,188		7,770
Purchase	454		29,000
Unrealized gain (loss)	1,789		1,508
Realized gain (loss)	322		-77
Settlements	-6,000		-13
Balance, end of period	34,753		38,188
Defined Benefit Plan, Fair Value of Plan Assets	34,753		38,188
Common Collective Trust - Real Estate
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	13,583		11,933
Common Collective Trust - Real Estate | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	9,719	[1]	8,541
Hedge Funds
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	25,034		29,647
Hedge Funds | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	$25,034	[2]	$29,647
[1]	The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. 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 the 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 fund does contain a participant withdrawal policy.
[2]	The fair value of the Hedge Funds is determined based on pricing provided or reviewed by the third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.

Employee_Benefit_Plans_Changes1

Employee Benefit Plans: Changes in Benefit Obligation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	$321,400,000		$363,235,000
Service Cost	5,448,000		6,433,000		5,720,000
Interest Cost	15,852,000		15,300,000		14,747,000
Actuarial (Gain) Loss	55,384,000	[1]	-38,252,000
Plan Amendments	0		0
Benefits Paid	-20,312,000	[2],[3]	-25,316,000	[2],[3]
Medicare Part D Accrued	0		0
Plan Participants' Contributions	0		0
Projected Benefit Obligation at End of Year	377,772,000		321,400,000		363,235,000
Defined Benefit Plan, One Time Lump Sum Benefit Paid	6,100,000		13,000,000
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	32,960,000		34,393,000
Service Cost	2,543,000		1,392,000
Interest Cost	1,447,000		1,328,000
Actuarial (Gain) Loss	5,814,000	[1]	-2,808,000
Plan Amendments	0		0
Benefits Paid	0		0
Benefits Paid	-1,553,000		-1,345,000
Medicare Part D Accrued	0		0
Plan Participants' Contributions	0		0
Projected Benefit Obligation at End of Year	41,211,000		32,960,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	45,778,000		46,681,000
Service Cost	1,700,000		1,674,000		1,610,000
Interest Cost	1,919,000		1,669,000		2,093,000
Actuarial (Gain) Loss	2,275,000	[1]	-3,379,000
Plan Amendments	0		1,585,000	[4]
Benefits Paid	-3,163,000	[5]	-3,269,000	[5]
Benefits Paid	-3,163,000		-5,123,000
Medicare Part D Accrued	-99,000		470,000
Plan Participants' Contributions	632,000		2,201,000
Projected Benefit Obligation at End of Year	$49,042,000		$45,778,000		$46,681,000
[1]	Change from 2013 reflects a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
[2]	Benefits paid include payments made to terminated vested employees who elected lump-sum offerings of $6.1 million in 2014 and $13 million in 2013.
[3]	Benefits paid include payments made to terminated vested employees who elected a lump-sum offering of $6.1 million in 2014 and $13 million in 2013.
[4]	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.
[5]	Assets of VEBA

Employee_Benefit_Plans_Changes2

Employee Benefit Plans: Changes in Plan Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	$280,362,000		$268,816,000
Investment income (loss)	29,283,000		24,362,000
Employer contributions	10,200,000		12,500,000
Retiree contributions	0		0
Benefits paid	-20,312,000	[1],[2]	-25,316,000	[1],[2]
Plan administrative expenses	0		0
Ending market value of plan assets	299,533,000		280,362,000
Lump Sum Payment	6,100,000		13,000,000
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	0		0
Investment income (loss)	0		0
Employer contributions	0		0
Retiree contributions	0		0
Benefits paid	0		0
Plan administrative expenses	0		0
Ending market value of plan assets	0		0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets	4,546,000	[3]	4,351,000	[3]
Investment income (loss)	-43,000	[3]	8,000	[3]
Employer contributions	2,733,000	[3]	1,923,000	[3]
Retiree contributions	632,000	[3]	1,533,000	[3]
Benefits paid	-3,163,000	[3]	-3,269,000	[3]
Plan administrative expenses	0	[3]	0	[3]
Ending market value of plan assets	$4,705,000	[3]	$4,546,000	[3]
[1]	Benefits paid include payments made to terminated vested employees who elected lump-sum offerings of $6.1 million in 2014 and $13 million in 2013.
[2]	Benefits paid include payments made to terminated vested employees who elected a lump-sum offering of $6.1 million in 2014 and $13 million in 2013.
[3]	Assets of VEBA

Employee_Benefit_Plans_Amounts

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$257,839	$162,648
Non-current liabilities	158,966	111,479
Regulatory liabilities	148,831	120,156
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	78,864	48,419
Current liabilities	0	0
Non-current liabilities	78,239	41,034
Regulatory liabilities	0	0
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	0	0
Current liabilities	1,486	1,491
Non-current liabilities	39,725	32,033
Regulatory liabilities	0	0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	7,137	5,535
Current liabilities	3,273	2,802
Non-current liabilities	41,002	38,412
Regulatory liabilities	$2,983	$3,141

Employee_Benefit_Plans_Accumul

Employee Benefit Plans: Accumulated Benefit Obligation (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$348,980	$293,142
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	30,229	27,893
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	49,042	45,778
Black Hills Corporation [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	135,582	110,847
Black Hills Corporation [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	29,843	27,380
Black Hills Corporation [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	12,809	12,101
Black Hills Utility Holdings [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	213,398	182,295
Black Hills Utility Holdings [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	386	513
Black Hills Utility Holdings [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	25,456	25,467
Cheyenne Light [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	0	0
Cheyenne Light [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	0	0
Cheyenne Light [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$10,777	$8,210

Employee_Benefit_Plans_Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$5,448	$6,433	$5,720
Interest Cost	15,852	15,300	14,747
Expected return on plan assets	-18,065	-18,615	-16,334
Amortization of prior service cost	62	63	89
Recognition of net actuarial loss (gain)	4,806	12,250	9,630
Net periodic benefit expense	8,103	15,431	13,852
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,498	1,392	889
Interest Cost	1,447	1,328	1,410
Expected return on plan assets	0	0	0
Amortization of prior service cost	2	2	3
Recognition of net actuarial loss (gain)	498	793	807
Net periodic benefit expense	3,445	3,515	3,109
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,700	1,674	1,610
Interest Cost	1,919	1,669	2,093
Expected return on plan assets	-85	-79	-78
Amortization of prior service cost	-428	-500	-500
Recognition of net actuarial loss (gain)	160	482	887
Net periodic benefit expense	$3,266	$3,246	$4,012

Employee_Benefit_Plans_Accumul1

Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	$10,996	$4,842
Prior service cost (gain)	51	64
Total accumulated other comprehensive (income) loss	11,047	4,906
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	7,174
Prior service cost (credit)	38
Total net periodic benefit cost expected to be recognized during calendar year 2015	7,212
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	8,396	4,939
Prior service cost (gain)	8	9
Total accumulated other comprehensive (income) loss	8,404	4,948
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	703
Prior service cost (credit)	1
Total net periodic benefit cost expected to be recognized during calendar year 2015	704
Other Postretirement Benefit Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	1,904	1,648
Prior service cost (gain)	-1,218	-1,213
Total accumulated other comprehensive (income) loss	686	435
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	295
Prior service cost (credit)	-278
Total net periodic benefit cost expected to be recognized during calendar year 2015	$17

Employee_Benefit_Plans_Defined

Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.75%		7.25%
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	2,635
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	-2,166
Effect of One Percentage Point Increase on Service and Interest Cost Components	168
Effect of One Percentage Point Decrease on Service and Interest Cost Components	-136
Healthcare trend rate pre-65 | Black Hills Corporation [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	7.50%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2027		2027
Healthcare trend rate pre-65 | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	7.50%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2027		2027
Healthcare trend rate pre-65 | Cheyenne Light [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	7.50%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2027		2027
Healthcare trend rate post-65 | Black Hills Corporation [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.25%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2024		2026
Healthcare trend rate post-65 | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.25%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2024		2026
Healthcare trend rate post-65 | Cheyenne Light [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.25%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2024		2026
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.64%		4.21%		3.44%
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 [Member] | Black Hills Corporation [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	4.68%		3.88%		4.70%
Supplemental Employee Retirement Plan [Member] | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	3.75%		3.00%		3.90%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.92%		4.62%		3.85%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	2.00%		2.00%		2.00%
Other Postretirement Benefit Plan [Member] | Black Hills Corporation [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	4.45%		3.65%		4.35%
Other Postretirement Benefit Plan [Member] | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	4.25%		3.50%		4.35%
Other Postretirement Benefit Plan [Member] | Cheyenne Light [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	5.15%		4.40%		4.65%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	4.20%		5.05%		4.30%
Rate of Increase in Compensation Levels	3.78%		3.78%		3.84%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.75%	[1]	7.25%	[1]	7.25%	[1]
Rate of Compensation Increase	3.78%		3.78%		3.75%
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 [Member] | Black Hills Corporation [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	5.10%		4.35%		4.68%
Pension Plans, Defined Benefit [Member] | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount Rate, Net Periodic Cost	5.00%		4.25%		4.60%
[1]	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.

Employee_Benefit_Plans_Project

Employee Benefit Plans: Projected Benefit Plan Payments (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$14,712
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	15,629
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	16,561
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	17,556
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	18,741
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	109,147
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	1,486
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,573
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,627
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,670
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,780
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	8,901
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	3,921
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	4,011
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	4,057
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	4,169
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	4,236
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$19,877

Commitments_And_Contingencies_1

Commitments And Contingencies: Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MW
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	$183,116
2016	131,716
2017	121,867
2018	69,000
2019	35,905
Thereafter	153,395
Purchase Commitment [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase of Fuel, Date of Contract Expiration	31-Dec-17
Purchase Option, Property [Member] | Wygen I Generating Facility [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-22
Busch Ranch Wind Farm [Member] | Electric Utilities [Member]
Long-term Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
PacifiCorp Purchase Power Agreement [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	50
Cost of Purchased Power	13,943		13,026		13,224
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-23
PacifiCorp Transmission [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	50
Cost of Purchased Power	1,227		1,384		1,215
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-23
Happy Jack Wind Purchase Power Agreeement [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	30
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	3-Sep-28
Happy Jack Wind Purchase Power Agreeement [Member] | Renewable Wind Energy, Cheyenne Light [Member]
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power	3,919		3,772		1,988
Silver Sage Wind Power Purchase Agreement [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	30
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	30-Sep-29
Silver Sage Wind Power Purchase Agreement [Member] | Renewable Wind Energy, Cheyenne Light [Member]
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power	4,798		4,809		3,269
Cargill Power Purchase Agreement [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	50
Cost of Purchased Power	9,286	[1]	12,291	[1]	14,236	[1]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-16
Busch Ranch Wind Farm [Member]
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	14.5
Cost of Purchased Power	$1,998		$1,856		$502
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	16-Oct-37
[1]	The 2013 and 2012 PPAs were one year contracts replaced by subsequent one year contracts upon expiration.

Commitments_And_Contingencies_2

Commitments And Contingencies: Short-term Purchase Agreement (Details) (Cargill Power Purchase Agreement [Member])	12 Months Ended
	Dec. 31, 2014
	MW
Cargill Power Purchase Agreement [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Short-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-15
Megawatts of Capacity Purchased	50

Commitments_And_Contingencies_3

Commitments And Contingencies: Related Party (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
	MW
Purchase Option, Property [Member] | Wygen I Generating Facility [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Megawatts of Capacity Purchased	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	31-Dec-22
Asset Purchase Option	$2.60
Power purchased [Member] | Pueblo Airport Generation [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Megawatts of Capacity Purchased	200
Lease Expiration Date	31-Dec-31

Commitments_And_Contingencies_4

Commitments And Contingencies: Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2014
	MW
M D U, Montana Dakota Utilities [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	25
City Of Gillette [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	23
Purchase Power Contract, MEAN, 5 Megawatts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	1-Apr-15
Purchase Power Contract, MEAN, 5 Megawatts [Member] | Neil Simpson I I [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	5
Purchase Power Contract, MEAN, 5 Megawatts [Member] | Wygen I I I Generating Facility [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	5
Purchase Power Contract, MEAN, 10 Megawatts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	31-May-23
Purchase Power Contract, MEAN, 10 Megawatts [Member] | Neil Simpson I I [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	10
Purchase Power Contract, MEAN, 10 Megawatts [Member] | Wygen I I I Generating Facility [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	10
Maximum [Member] | M D U, Montana Dakota Utilities [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	50

Commitments_And_Contingencies_5

Commitments And Contingencies: Purchase Commitment (Details) (Capital Addition Purchase Commitments [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Purchase Price of Acquisition	$17

Commitments_And_Contingencies_6

Commitments And Contingencies: Reimbursement Agreement (Details) (Electric Utilities [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt	$544,753		$396,948
Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt	10,000	[1]	10,000	[1]
Long-term Debt, Maturity Date	1-Mar-27
Industrial Development Revenue Bonds Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	$7,000	[1]	$7,000	[1]
Long-term Debt, Maturity Date	1-Sep-21
[1]	Variable interest rate.

Commitments_And_Contingencies_7

Commitments And Contingencies: Environmental Contingencies (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Electric Utilities [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$3.90
Manufactured Gas Plant [Member] | Gas Utilities [Member]
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.3
Loss Contingency, Range of Possible Loss, Minimum	2.7
Loss Contingency, Range of Possible Loss, Maximum	6.3
Accrual for Environmental Loss Contingencies, Gross	$2.70

Commitments_And_Contingencies_8

Commitments And Contingencies: Legal Proceedings (Details) (Oil Creek Fire [Member], Loss from Catastrophes [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Minimum [Member]
Loss Contingencies [Line Items]
Insurance Coverage Deductible Per Occurrence	$1
Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$55

Guarantees_Guarantees_Details

Guarantees: Guarantees (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Coal Mining [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$63,900	[1]
Guarantor Obligations, Term	Ongoing
Gas Utilities [Member] | Payment Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$70,000
[1]	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_Unaudited2

Oil and Gas Reserves (Unaudited): Oil and Gas Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	Mcfe	Mcfe
	PUD_Location	PUD_Location
Reserve Quantities [Line Items]
Wells in Process of Drilling	1,205
Gas and Oil Acreage, Leased	240,816
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	16,500,000
Reserves Replaced	165.00%
Proved Undeveloped Reserves, Revisions of Previous Estimates	8,500,000
Proved Undeveloped Reserve Locations	34
Proved Undeveloped Reserves	12,100,000
Estimated Future Development Costs of Proved Undeveloped Wells	$41.90
PUD Locations in Reserves for Five Or More Years	0
Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	13	23
Proved Undeveloped Reserves	3,200,000	4,700,000
Estimated Future Development Costs of Proved Undeveloped Wells	10.5	15.9
Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	21
Proved Undeveloped Reserves	8,900,000
Estimated Future Development Costs of Proved Undeveloped Wells	31.5
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	4,000,000
Commodity Prices [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	2,900,000
Oil and Gas Well Performance [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	2,700,000
Oil and Gas Reserve Revisions, Five Year Reserve Aging Limit [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	0
Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	12,300,000
Piceance Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	1	1
Proved Undeveloped Reserves		2,300,000
Estimated Future Development Costs of Proved Undeveloped Wells		6.4
Piceance Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	2
Proved Undeveloped Reserves	6,700,000
Estimated Future Development Costs of Proved Undeveloped Wells	17.5
Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	500,000
PUD Developed, PUD location	7
Capital Expenditure for Proved Undeveloped Reserve	3.9
Proved Developed Reserves (Energy)	600,000
Williston Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	12	21
Proved Undeveloped Reserves		1,800,000
Estimated Future Development Costs of Proved Undeveloped Wells		8.6
Williston Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	18
Proved Undeveloped Reserves	200,000
Estimated Future Development Costs of Proved Undeveloped Wells	1
Williston Basin [Member] | Oil and Gas Reserve Revisions, Reserves Sold [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	2
Proved Undeveloped Reserves	300,000
Estimated Future Development Costs of Proved Undeveloped Wells	0.7
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	3,700,000
Powder River Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	1
Proved Undeveloped Reserves	2,000,000
Estimated Future Development Costs of Proved Undeveloped Wells	13
Powder River Basin [Member] | Oil and Gas Reserve Revisions, Operating Costs [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	-100,000
San Juan Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations		1
Proved Undeveloped Reserves		600,000
Estimated Future Development Costs of Proved Undeveloped Wells		0.9
San Juan Basin [Member] | Reserves Dropped [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations	1
Proved Undeveloped Reserves	600,000
Estimated Future Development Costs of Proved Undeveloped Wells	$0.90
San Juan Basin [Member] | Oil and Gas Reserve Revisions, Economics [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	900,000
Proved Undeveloped Reserve Locations	1
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Entity Operates	10

Oil_and_Gas_Reserves_Unaudited3

Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) (Oil and Gas [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas [Member]
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved Reserves	$4,881	$234	$2,437
Unproved Reserves	5,056	6,022	33,052
Exploration Costs	54,355	12,817	115
Development Costs	52,262	48,641	73,877
Asset Retirement Obligation Incurred	68	143	158
Oil and Gas Property Acquisition, Exploration, and Development Activities	$116,622	$67,857	$109,639

Oil_and_Gas_Reserves_Unaudited4

Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Proved Developed And Undevleoped Reserves [Roll Forward]
Average Crude Oil Price, Per Barrel, NYMEX	94.99		96.94		94.71
Average Natural Gas Price Per MCF, NYMEX	4.35		3.67		2.76
Average Natural Gas Liquids Price Per MCF, NYMEX	0	[1]
Average Crude Oil Price Per Barrel, Wellhead	85.8		89.79		85.31
Average Natural Gas Price Per MCF, Wellhead	3.33		3.45		2.24
Average Natural Gas Liquids Price Per MCF, Wellhead	34.81
Oil [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	3,921		4,116		6,223
Production	-337	[2]	-336	[2]	-560	[2]
Additions, Acquisitions (Sales)	-40		-30		-2,025	[3]
Additions, Extensions, Discoveries (bcfe)	733		379		449
Reserves, Revisions of Previous Estimates	-1		-208		29
Balance at End of Year	4,276		3,921		4,116
Proved Developed Reserves (Volume)	3,780		3,689		3,929
Proved Undeveloped Reserve (Volume)	496		232		187
Natural Gas [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	63,190		55,985		95,904
Production	-7,156	[2]	-6,984	[2]	-8,686	[2]
Additions, Acquisitions (Sales)	-61		-46		-3,070	[3]
Additions, Extensions, Discoveries (bcfe)	11,003		10,456		2,898
Reserves, Revisions of Previous Estimates	-1,536		3,779		-31,061
Balance at End of Year	65,440		63,190		55,985
Proved Developed Reserves (Volume)	57,427		60,224		55,708
Proved Undeveloped Reserve (Volume)	8,013		2,966		279
Natural Gas Liquids [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	0
Production	-135	[2]
Additions, Acquisitions (Sales)	0
Additions, Extensions, Discoveries (bcfe)	182
Reserves, Revisions of Previous Estimates	1,673
Balance at End of Year	1,720
Proved Developed Reserves (Volume)	1,530
Proved Undeveloped Reserve (Volume)	191
[1]	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, iso butane, 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.
[2]	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.
[3]	Reflects the sale of the majority of the Williston Basin assets during 2012.

Oil_and_Gas_Reserves_Unaudited5

Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Unproved oil and gas properties	$75,329	$62,553	$59,526
Proved oil and gas properties	807,518	725,345	662,444
Gross capitalized costs	882,847	787,898	721,970
Accumulated depreciation, depletion and amortization and valuation allowances	-578,108	-555,263	-534,777	[1]
Net capitalized costs	$304,739	$232,635	$187,193
[1]	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Oil_and_Gas_Reserves_Unaudited6

Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenue	$55,114	$54,884	$79,072
Production costs	22,155	20,140	23,483
Gain on sale of assets	0	0	-29,129
Depreciation, depletion and amortization and valuation provisions	26,626	20,611	37,323
Impairment of long-lived assets	0	0	26,868
Total costs	48,781	40,751	58,545
Results of operations from producing activities before tax	6,333	14,133	20,527
Income tax benefit (expense)	-2,185	-4,876	-7,082
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$4,148	$9,257	$13,445

Oil_and_Gas_Reserves_Unaudited7

Oil and Gas Reserves (Unaudited): Unproved Properties Excluded from Amortization (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	$70,201,000
Exploration cost	34,166,000
Capitalized interest	5,128,000
Total	109,495,000
Current Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	16,077,000
Exploration cost	23,954,000
Capitalized interest	207,000
Total	40,238,000
Prior Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	4,889,000
Exploration cost	10,212,000
Capitalized interest	748,000
Total	15,849,000
More Than One Year, Less Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	35,823,000
Exploration cost	0
Capitalized interest	360,000
Total	36,183,000
More Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	13,412,000
Exploration cost	0
Capitalized interest	3,813,000
Total	17,225,000
Oil and Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$1,000,000	$1,100,000	$700,000

Oil_and_Gas_Reserves_Unaudited8

Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$675,973	$602,501	$502,769
Future production costs	-245,180	-213,578	-186,695
Future development costs, including plugging and abandonment	-45,123	-40,557	-8,462
Future income tax expense	-29,523	-81,566	-69,877
Future net cash flows	356,147	266,800	237,735
10% annual discount for estimated timing of cash flows	-173,125	-107,375	-101,632
Standardized measure of discounted future net cash flows	$183,022	$159,425	$136,103	$203,357

Oil_and_Gas_Reserves_Unaudited9

Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$159,425	$136,103	$203,357
Sales and transfers of oil and gas produced, net of production costs	-32,139	-35,932	-48,905
Net changes in prices and production costs	-28,544	15,126	-42,639
Extensions, discoveries and improved recovery, less related costs	17,582	29,574	19,870
Changes in future development costs	3,195	-12,216	43,854
Development costs incurred during the period	2,079	3,554	21,931
Revisions of previous quantity estimates	23,722	12,851	-86,277
Accretion of discount	18,437	15,126	25,509
Net change in income taxes	19,265	-3,892	36,578
Purchases of reserves	0	0	0
Sales of reserves	0	-869	-37,175	[1]
Standardized measure - end of year	$183,022	$159,425	$136,103
[1]	Reflects sale of Williston Basin assets in 2012.

Sale_Of_Operating_Assets_and_D2

Sale Of Operating Assets and Discontinued Operations: Sale of Operating Assets (Details) (USD $)	12 Months Ended				0 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Sep. 18, 2012	Sep. 27, 2012		Dec. 31, 2012
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Assets	$0	$0	$29,129,000	[1]
Electric Utilities [Member]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Assets			0
Electric Utilities [Member] | Busch Ranch Wind Farm [Member]
Significant Acquisitions and Disposals [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
Proceeds from Sale of Property, Plant, and Equipment					25,000,000
Oil and Gas [Member]
Significant Acquisitions and Disposals [Line Items]
Gain (Loss) on Sale of Assets			29,129,000	[1]
Oil and Gas [Member] | Williston Basin Assets [Member]
Significant Acquisitions and Disposals [Line Items]
Effective Date, Disposal			1-Jul-12
Gain (Loss) on Sale of Assets			29,000,000
Proceeds from Sale of Productive Assets [Abstract]
Post Close Adjustment								2,793,000
Transaction Costs						-1,400,000
Back-in Contract Termination Fee						-16,847,000	[2]
Oil and Gas [Member] | Cash Proceeds Received on Date of Sale [Member] | Williston Basin Assets [Member]
Proceeds from Sale of Productive Assets [Abstract]
Proceeds from Sale of Oil and Gas Property and Equipment						243,314,000
Net Cash Proceeds from Sale of Oil and Gas Property and Equipment						243,314,000
Oil and Gas [Member] | Net Cash Proceeds [Member] | Williston Basin Assets [Member]
Proceeds from Sale of Productive Assets [Abstract]
Proceeds from Sale of Oil and Gas Property and Equipment								227,860,000
Net Cash Proceeds from Sale of Oil and Gas Property and Equipment								$227,860,000
[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).
[2]	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Sale_Of_Operating_Assets_and_D3

Sale Of Operating Assets and Discontinued Operations: Discontinued Operations (Details) (USD $)	3 Months Ended				12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Acquisitions and Disposals [Line Items]
Proceeds from sale of business operations					$0	$0	$107,511,000
Income (loss) from discontinued operations, net of tax	-884,000	0	0	0	0	-884,000	-6,977,000
Business Exit Costs							2,500,000
Energy Marketing [Member]
Significant Acquisitions and Disposals [Line Items]
Disposal Date						29-Feb-12
Proceeds from sale of business operations							108,000,000
Funds Retained, Sale of Business							58,000,000
Disposal Group, Including Discontinued Operation, Revenue						0	-604,000
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax						0	-6,061,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax						-1,391,000	-4,184,000
Discontinued Operation, Tax Effect of Discontinued Operation						507,000	3,268,000
Income (loss) from discontinued operations, net of tax						-884,000	-6,977,000	[1]
Minimum [Member] | Energy Marketing [Member]
Significant Acquisitions and Disposals [Line Items]
Post Close Adjustment						$1,100,000	$1,400,000
[1]	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended December 31, 2012.

Quarterly_Historical_Data_Unau2

Quarterly Historical Data (Unaudited): Quarterly Historical Data (Unaudited) (Details) (USD $)	3 Months Ended												12 Months Ended			0 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 19, 2013
Selected Quarterly Financial Information [Line Items]
Revenue	$378,077,000	$272,087,000	$283,237,000	$460,169,000	$355,448,000		$259,907,000		$279,826,000		$380,671,000		$1,393,570,000	$1,275,852,000	$1,173,884,000
Operating income	69,951,000	54,404,000	46,577,000	89,598,000	71,103,000		55,566,000		49,037,000		79,846,000		260,530,000	255,552,000	243,711,000
Income (loss) from continuing operations	34,007,000	26,836,000	19,820,000	48,118,000	19,007,000	[1],[2]	23,124,000	[1]	30,518,000	[1]	43,197,000	[1]	128,781,000	115,846,000	88,505,000
Income (loss) from discontinued operations					-884,000		0		0		0		0	-884,000	-6,977,000
Net income (loss) available for common stock	34,007,000	26,836,000	19,820,000	48,118,000	18,123,000	[1],[2]	23,124,000	[1]	30,518,000	[1]	43,197,000	[1]	128,781,000	114,962,000	81,528,000
Income (loss) from continuing operations, Basic (usd per share)					$0.43		$0.52		$0.69		$0.98		$2.90	$2.62	$2.02
Income (loss) from discontinued operations, Basic (usd per share)					($0.02)		$0		$0		$0		$0	($0.02)	($0.16)
Total income (loss) per share, Basic (usd per share)	$0.77	$0.60	$0.45	$1.09	$0.41		$0.52		$0.69		$0.98		$2.90	$2.60	$1.86
Income (loss) from continuing operations - Diluted (usd per share)					$0.43		$0.52		$0.69		$0.97		$2.89	$2.61	$2.01
Income (loss) from discontinued operations - Diluted (usd per share)					($0.02)		$0		$0		$0		$0	($0.02)	($0.16)
Total income (loss) per share, Diluted (usd per share)	$0.76	$0.60	$0.44	$1.08	$0.41		$0.52		$0.69		$0.97		$2.89	$2.59	$1.85
Dividends paid per share	$0.39	$0.39	$0.39	$0.39	$0.38		$0.38		$0.38		$0.38		$1.56	$1.52	$1.48
Unrealized Gain (Loss) Unhedged Derivative Instrument, Net of Tax					500,000		2,000,000		12,000,000		4,800,000
Black Hills Corporation [Member] | Senior Unsecured Notes Due 2014 [Member]
Selected Quarterly Financial Information [Line Items]
Interest Expense, Prepayment of Debt, Net of Tax					7,600,000
Extinguishment of Debt, Amount														250,000,000
Power Generation [Member]
Selected Quarterly Financial Information [Line Items]
Revenue													6,401,000	4,648,000	4,189,000
Operating income													49,892,000	47,760,000	44,799,000
Power Generation [Member] | Project Financing Debt Due 2016 [Member]
Selected Quarterly Financial Information [Line Items]
Interest Expense, Prepayment of Debt, Net of Tax					6,600,000
Extinguishment of Debt, Amount																$87,000,000
Common Stock [Member] | Maximum [Member]
Selected Quarterly Financial Information [Line Items]
Share Price	$57.17	$62.13	$61.41	$59.05	$54.83		$55.09		$50.53		$44.32
Common Stock [Member] | Minimum [Member]
Selected Quarterly Financial Information [Line Items]
Share Price	$47.11	$47.87	$55.23	$51.09	$47		$46.62		$43.19		$36.89
[1]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.
[2]	Fourth quarter 2013 includes $7.6 million after-tax for a make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt and a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.

Schedule_II_Consolidated_Valua1

Schedule II Consolidated Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for Doubtful Accounts, Balance at Beginning of Year	$1,237	$768	$1,661
Allowance for Doubtful Accounts, Adjustments	0	0	0
Allowance for Doubtful Accounts, Charged to Cost and Expense	4,470	2,780	1,913
Allowance for Doubtful Accounts, Recoveries and Other Additions	4,233	4,999	3,822
Allowance for Doubtful Accounts, Write-Offs and Other Deductions	-8,424	-7,310	-6,628
Allowance for Doubtful Accounts, Balance at End of Year	$1,516	$1,237	$768