Black Hills (BKH) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document Information Document

Document Information Document - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 29, 2016	Jun. 30, 2015
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		51,194,387
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 1,925,452,517

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Revenue:
Total revenue	$ 1,304,605		$ 1,393,570	$ 1,275,852
Utilities -
Fuel, purchased power and cost of natural gas sold	456,887		581,782	492,147
Operations and maintenance	272,407		270,954	261,919
Non-regulated energy operations and maintenance	88,702		88,141	83,762
Depreciation, depletion and amortization	155,370		144,745	137,324
Impairment of long-lived assets	249,608	[1]	0	0
Taxes - property, production and severance	44,353		43,580	40,012
Other operating expenses	7,483		500	1,243
Total operating expenses	1,274,810		1,129,702	1,016,407
Operating income	29,795		263,868	259,445
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)	(86,278)		(73,017)	(113,979)
Allowance for funds used during construction - borrowed	1,250		1,075	1,130
Capitalized interest	1,309		982	1,061
Unrealized gain (loss) on interest rate swaps, net	0		0	30,169
Interest income	1,621		1,925	1,723
Allowance for funds used during construction - equity	897		994	607
Other expense	(372)		(377)	(694)
Other income	2,256		2,065	1,971
Total other income (expense)	(79,317)		(66,353)	(78,012)
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes	(49,522)		197,515	181,433
Equity in earnings (loss) of unconsolidated subsidiaries	(344)		(1)	(86)
Impairment of equity investments	(4,405)	[1]	0	0
Income tax benefit (expense)	22,160		(66,625)	(63,040)
Income (loss) from continuing operations	(32,111)		130,889	118,307
Income (loss) from discontinued operations, net of tax	0		0	(884)
Net income (loss) available for common stock	$ (32,111)		$ 130,889	$ 117,423
Earnings (loss) per share, Basic -
Income (loss) from continuing operations (usd per share)	$ (0.71)		$ 2.95	$ 2.68
Income (loss) from discontinued operations (usd per share)	0		0	(0.02)
Total income (loss) per share, Basic (usd per share)	(0.71)		2.95	2.66
Earnings (loss) per share, Diluted -
Income (loss) from continuing operations (usd per share)	(0.71)		2.93	2.66
Income (loss) from discontinued operations (usd per share)	0		0	(0.02)
Total income (loss) per share, Diluted (usd per share)	$ (0.71)		$ 2.93	$ 2.64
Weighted average common shares outstanding:
Basic (in shares)	45,288		44,394	44,163
Diluted (in shares)	45,288		44,598	44,419
Utilities Group [Member]
Revenue:
Total revenue	$ 1,219,526		$ 1,300,969	$ 1,191,133
Non Regulated Energy Group [Member]
Revenue:
Total revenue	$ 85,079		$ 92,601	$ 84,719
[1]	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss) available for common stock	$ (32,111)	$ 130,889	$ 117,423
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(1,375), $5,004 and $(3,813), respectively)	2,657	(10,590)	8,237
Benefit plan liability adjustments - prior service (costs) (net of tax of $0, $(17) and $185, respectively)	0	237	(406)
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(972), $(348) and $(971), respectively)	1,850	646	1,820
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $88, $76 and $88, respectively)	(150)	(141)	(165)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(4,496), $(5,239) and $(2,445), respectively)	8,174	8,906	4,534
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $4,271, $(2,344) and $(2,016), respectively)	(6,542)	3,320	4,046
Other comprehensive income (loss), net of tax	5,989	2,378	18,066
Comprehensive income (loss)	$ (26,122)	$ 133,267	$ 135,489

Statement of Comprehensive Inco

Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Benefit plan liability adjustments - net gain (loss), Tax	$ (1,375)	$ 5,004	$ (3,813)
Benefit plan liability adjustments - prior service (costs), Tax	0	(17)	185
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(972)	(348)	(971)
Reclassification adjustment of benefit plan liability - prior service cost, tax	88	76	88
Fair value adjustment on derivatives designated as cash flow hedges, Tax	(4,496)	(5,239)	(2,445)
Reclassification adjustment of cash flow hedges settled and included in net income (loss), Tax	$ 4,271	$ (2,344)	$ (2,016)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 456,535	$ 21,218
Restricted cash and equivalents	1,697	2,056
Accounts receivable, net	147,486	189,992
Materials, supplies and fuel	86,943	91,191
Derivative assets, current	0	0
Income tax receivable, net	368	2,053
Deferred income tax assets, net, current	0	48,288
Regulatory assets, current	57,359	74,396
Other current assets	71,763	24,842
Total current assets	822,151	454,036
Investments	11,985	17,294
Property, plant and equipment	4,976,778	4,563,400
Less accumulated depreciation and depletion	(1,717,684)	(1,357,929)
Total property, plant and equipment, net	3,259,094	3,205,471
Other assets:
Goodwill	359,759	353,396
Intangible assets, net	3,380	3,176
Derivative assets, non-current	3,441	0
Regulatory assets, non-current	175,125	183,443
Other assets, non-current	20,566	29,086
Total other assets, non-current	562,271	569,101
TOTAL ASSETS	4,655,501	4,245,902
Current liabilities:
Accounts payable	105,468	124,139
Accrued liabilities	232,061	170,115
Derivative liabilities, current	2,835	3,340
Regulatory liabilities, current	4,865	3,687
Notes payable	76,800	75,000
Current maturities of long-term debt	0	275,000
Total current liabilities	422,029	651,281
Long-term debt, net of current maturities	1,866,866	1,267,589
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	450,579	511,952
Derivative liabilities, non-current	156	2,680
Regulatory liabilities, non-current	148,176	145,144
Benefit plan liabilities	146,459	158,966
Other deferred credits and other liabilities	155,369	154,406
Total deferred credits and other liabilities	$ 900,739	$ 973,148
Commitments and contingencies (See Notes 2, 6, 7, 8, 9, 14, 18, 19, and 20)
Stockholders’ equity:
Common stock $1 par value; 100,000,000 shares authorized; issued: 51,231,861 and 44,714,072 shares, respectively	$ 51,232	$ 44,714
Additional paid-in capital	953,044	748,840
Retained earnings	472,534	577,249
Treasury stock at cost - 39,720 and 42,226 shares, respectively	(1,888)	(1,875)
Accumulated other comprehensive income (loss)	(9,055)	(15,044)
Total stockholders’ equity	1,465,867	1,353,884
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 4,655,501	$ 4,245,902

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Common Stock, Par Value (usd per share)	$ 1	$ 1
Common Stock, Shares, Outstanding	51,192,141	44,671,846
Treasury Stock, Shares	39,720	42,226
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	51,231,861	44,714,072

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income (loss) available for common stock	$ (32,111)	$ 130,889	$ 117,423
(Income) loss from discontinued operations, net of tax	0	0	884
Income (loss) from continuing operations	(32,111)	130,889	118,307
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	155,370	144,745	137,324
Deferred financing cost amortization	6,364	2,127	6,763
Impairment of long-lived assets and equity method investments	254,013	0	0
Stock compensation	4,076	9,329	12,595
Unrealized (gain) loss on interest rate swaps, net	0	0	(30,169)
Deferred income taxes	(26,028)	70,232	65,216
Employee benefit plans	20,616	14,814	22,194
Other adjustments, net	(4,872)	14,415	9,826
Change in certain operating assets and liabilities:
Materials, supplies and fuel	7,197	(4,563)	(5,770)
Accounts receivable, unbilled revenues and other current assets	40,125	(18,684)	(18,945)
Accounts payable and other current liabilities	(1,070)	16,027	15,336
Regulatory assets	21,883	(38,774)	8,323
Regulatory liabilities	1,675	(7,633)	(3,299)
Contributions to defined benefit pension plans	(10,200)	(10,200)	(12,500)
Other operating activities, net	(9,034)	733	312
Net cash provided by operating activities of continuing operations	428,004	323,457	325,513
Net cash (used in) operating activities of discontinued operations	0	0	(884)
Net cash provided by operating activities	428,004	323,457	324,629
Investing activities:
Property, plant and equipment additions	(455,481)	(398,494)	(354,749)
Acquisition of net assets	(21,970)	0	0
Other investing activities	1,062	(2,653)	5,471
Net cash provided by (used in) investing activities of continuing operations	(476,389)	(401,147)	(349,278)
Net cash provided by (used in) investing activities of discontinued operations	0	0	0
Net cash provided by (used in) investing activities	(476,389)	(401,147)	(349,278)
Financing activities:
Dividends paid on common stock	(72,604)	(69,636)	(67,587)
Common stock issued	248,759	3,251	4,354
Short-term borrowings - issuances	397,310	396,250	337,650
Short-term borrowings - repayments	(395,510)	(403,750)	(532,150)
Long-term debt - issuance	300,000	160,000	800,000
Long-term debt - repayments	(275,000)	(12,200)	(445,906)
Equity units - issuance	290,030	0	0
De-designated interest rate swap settlement	0	0	(63,939)
Other financing activities	(9,283)	17,152	(15,394)
Net cash provided by (used in) financing activities of continuing operations	483,702	91,067	17,028
Net cash provided by (used in) financing activities of discontinued operations	0	0	0
Net cash provided by (used in) financing activities	483,702	91,067	17,028
Net change in cash and cash equivalents	435,317	13,377	(7,621)
Cash and cash equivalents:
Cash and cash equivalents beginning of year	21,218	7,841	15,462
Cash and cash equivalents end of year	$ 456,535	$ 21,218	$ 7,841

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]
Shares, Issued Period Start at Dec. 31, 2012		44,278,189
Stockholders' Equity Attributable to Parent Period Start at Dec. 31, 2012	$ 1,205,800	$ 44,278	$ (2,245)	$ 733,095	$ 466,160	$ (35,488)
Treasury Stock, Shares, Period Start at Dec. 31, 2012			71,782
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	117,423	0	$ 0	0	117,423	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
Shares, Issued Period End at Dec. 31, 2013		44,550,239
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2013	$ 1,283,500	$ 44,550	$ (1,968)	742,344	515,996	(17,422)
Treasury Stock, Shares, Period End at Dec. 31, 2013			50,877
Dividends, Common Stock [Abstract]
Dividends per share paid (usd per share)	$ 1.52
Net income (loss) available for common stock	$ 130,889	0	$ 0	0	130,889	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
Tax effect of 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
Shares, Issued Period End at Dec. 31, 2014		44,714,072
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2014	$ 1,353,884	$ 44,714	$ (1,875)	748,840	577,249	(15,044)
Treasury Stock, Shares, Period End at Dec. 31, 2014	42,226		42,226
Dividends, Common Stock [Abstract]
Dividends per share paid (usd per share)	$ 1.56
Net income (loss) available for common stock	$ (32,111)	0	$ 0	0	(32,111)	0
Other comprehensive income (loss), net of tax	5,989	$ 0	$ 0	0	0	5,989
Dividends on common stock, shares		0	0
Dividends on common stock	(72,604)	$ 0	$ 0	0	(72,604)	0
Share-based compensation, shares		126,765	(2,506)
Share-based compensation	4,240	$ 127	$ (13)	4,126	0	0
Tax effect of share-based compensation	0	$ 0	$ 0	0	0	0
Issuance of common stock, shares		6,325,000
Issuance of common stock	254,581	$ 6,325		248,256
Issuance costs	(17,926)			(17,926)
Premium on Equity Units	(33,118)			(33,118)
Dividend reinvestment and stock purchase plan, shares		66,024	0
Dividend reinvestment and stock purchase plan	2,957	$ 66	$ 0	2,891	0	0
Other stock transactions, shares		0	0
Other stock transactions	(25)	$ 0	$ 0	(25)	0	0
Shares, Issued Period End at Dec. 31, 2015		51,231,861
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2015	$ 1,465,867	$ 51,232	$ (1,888)	$ 953,044	$ 472,534	$ (9,055)
Treasury Stock, Shares, Period End at Dec. 31, 2015	39,720		39,720
Dividends, Common Stock [Abstract]
Dividends per share paid (usd per share)	$ 1.62

Business Description And Signif

Business Description And Significant Accounting Policies:	12 Months Ended
	Dec. 31, 2015
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 22 for additional information. For further descriptions of our reportable business segments, see Note 5 . Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All inter-company balances and transactions have been eliminated in consolidation. For additional information on inter-company revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information. 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 22 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 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): 2015 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 45,296 $ 39,052 $ (689 ) $ 83,659 Gas Utilities 26,713 29,691 (1,039 ) 55,365 Power Generation 1,187 — — 1,187 Coal Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,026 — — 1,026 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 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 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): December 31, 2015 December 31, 2014 Materials and supplies $ 55,726 $ 49,555 Fuel - Electric Utilities 5,567 6,637 Natural gas in storage held for distribution 25,650 34,999 Total materials, supplies and fuel $ 86,943 $ 91,191 Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are valued using weighted-average cost. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2015 December 31, 2014 Accrued employee compensation, benefits and withholdings $ 43,342 $ 45,192 Accrued property taxes 32,393 33,688 Accrued payments related to litigation expenses and settlements 38,750 — Customer deposits and prepayments 53,496 26,141 Accrued interest and contract adjustment payments 25,762 14,913 Other (none of which is individually significant) 38,318 50,181 Total accrued liabilities $ 232,061 $ 170,115 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. 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 2015. No ceiling test write-down was recorded in 2014 or 2013. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We 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 21 . 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, 2015 . 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, 2013 $ 250,487 $ 94,144 $ 8,765 $ 353,396 Additions — — — — Ending balance at December 31, 2014 $ 250,487 $ 94,144 $ 8,765 $ 353,396 Additions (a) 6,363 — — 6,363 Ending balance at December 31, 2015 $ 256,850 $ 94,144 $ 8,765 $ 359,759 _________________ (a) Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. 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 25 years . Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2015 2014 2013 Intangible assets, net, beginning balance $ 3,176 $ 3,397 $ 3,620 Additions 434 — — Amortization expense (a) (230 ) (221 ) (223 ) Intangible assets, net, ending balance $ 3,380 $ 3,176 $ 3,397 _________________ (a) 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 (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method. Additional information is included in Note 8 . Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Oil and Gas Segment: • The commodity contracts for the Oil and Gas segment are valued under the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure. 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 10 . Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, 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 (Loss). Legal Costs Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. Regulatory Accounting Our 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) December 31, 2015 December 31, 2014 Regulatory assets Deferred energy and fuel cost adjustments - current (a)(d) 1 $ 24,751 $ 23,820 Deferred gas cost adjustments (a)(d) 2 15,521 37,471 Gas price derivatives (a) 5 23,583 18,740 AFUDC (b) 45 12,870 12,358 Employee benefit plans (c) 12 83,986 97,126 Environmental (a) subject to approval 1,180 1,314 Asset retirement obligations (a) 44 457 3,287 Bond issue cost (a) 22 3,133 3,276 Renewable energy standard adjustment (a) 5 5,068 9,622 Flow through accounting (c) 35 29,722 25,887 Decommissioning costs (b) 10 18,310 12,484 Other regulatory assets (a) 15 13,903 12,454 $ 232,484 $ 257,839 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 7,814 $ 6,496 Employee benefit plans (c) 12 47,218 53,139 Cost of removal (a) 44 90,045 78,249 Other regulatory liabilities (c) 25 7,964 10,947 $ 153,041 $ 148,831 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively. (d) Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. 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

Acquisition_

Acquisition:	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition	ACQUISITION On February 12, 2016, Black Hills Utility Holdings acquired SourceGas from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , which included an estimated $200 million in capital expenditures through closing and the assumption of $760 million in debt at closing. This transaction is subject to final post-close working capital adjustments. To fund the SourceGas Transaction, we have put in place the following permanent financing: • On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95% , 10 -year senior notes due 2026, and $250 million of 2.5% , 3 -year senior notes due 2019. Net proceeds from the offering were $546 million ; • On November 23, 2015, we completed the offerings of common stock and equity units. We issued 6.325 million shares of common stock for net proceeds of $246 million and 5.98 million equity units for net proceeds of $290 million ; and We funded the cash consideration and out-of-pocket expenses payable in connection with the SourceGas Acquisition using the proceeds from the above offerings, other cash on hand and draws under our revolving credit agreement. Our $1.17 billion bridge commitment signed on July 12, 2015 was reduced to $88 million on January 13, 2016, with respect to reductions from our equity and debt offerings. The remaining commitment terminated on February 12, 2016 upon closing of the SourceGas Acquisition. SourceGas primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 mile regulated intrastate natural gas transmission pipeline in Colorado. As the initial accounting for the business combination was not complete at the time these financial statements were issued, the purchase price allocation and pro-forma income statement disclosures have not been disclosed.

Property, Plant And Equipment_

Property, Plant And Equipment:	12 Months Ended
	Dec. 31, 2015
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 2015 2014 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 $ 1,136,847 43 $ 1,125,845 45 25 65 Electric transmission 301,280 52 284,032 49 40 70 Electric distribution 785,351 48 718,342 44 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 180,840 24 152,982 21 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,670,629 2,547,512 Construction work in progress 98,918 49,700 Total electric plant 2,769,547 2,597,212 Less accumulated depreciation and amortization 540,634 484,406 Electric plant net of accumulated depreciation and amortization $ 2,228,913 $ 2,112,806 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 15 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. 2015 2014 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 30 $ 13 37 30 30 Gas transmission 24,081 62 24,090 54 53 70 Gas distribution 607,224 44 557,405 46 41 56 General 100,765 21 90,085 19 16 22 Total gas plant in service 732,083 671,593 Construction work in progress 9,437 16,072 Total gas plant 741,520 687,665 Less accumulated depreciation and amortization 106,778 92,035 Gas plant net of accumulated depreciation and amortization $ 634,742 $ 595,630 2015 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 $ 156,721 $ 2,182 $ 158,903 $ 51,471 $ 107,432 33 2 40 Coal Mining 154,630 3,649 158,279 97,663 60,616 13 2 59 Oil and Gas 1,132,776 — 1,132,776 925,908 206,868 24 3 25 $ 1,444,127 $ 5,831 $ 1,449,958 $ 1,075,042 $ 374,916 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 — 962,395 646,640 315,755 24 3 25 $ 1,261,793 $ 6,010 $ 1,267,803 $ 784,973 $ 482,830 2015 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 376 $ 15,377 $ 15,753 $ (4,770 ) $ 20,523 10 5 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. 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 Black Hills Colorado IPP.

Jointly Owned Facilities_

Jointly Owned Facilities:	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Jointly Owned Facilities	JOINTLY OWNED FACILITIES Utility Plant Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. • 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 (Loss). Each of the respective owners is responsible for providing its own financing. • Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations. At December 31, 2015 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 111,532 $ 1,039 $ 56,812 Transmission Tie $ 19,648 $ — $ 5,390 Wygen I $ 108,732 $ 636 $ 35,531 Wygen III $ 137,860 $ 446 $ 16,217 Busch Ranch Wind Project $ 18,899 $ — $ 2,345

Business Segments Information_

Business Segments Information:	12 Months Ended
	Dec. 31, 2015
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 22 . Segment information was as follows (in thousands): Total Assets (net of inter-company eliminations) as of December 31, 2015 2014 Utilities: Electric (a) $ 2,859,720 $ 2,748,680 Gas 864,858 906,922 Non-regulated Energy: Power Generation (a) 60,864 76,945 Coal Mining 76,358 74,407 Oil and Gas 208,956 332,343 Corporate (b) 584,745 106,605 Total assets $ 4,655,501 $ 4,245,902 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2015 2014 Utilities: Electric Utilities $ 202,075 $ 193,199 Gas Utilities 69,496 70,528 Non-regulated Energy: Power Generation 2,694 2,379 Coal Mining 5,767 6,676 Oil and Gas 168,925 109,439 Corporate 9,864 9,046 Total capital expenditures and asset acquisitions $ 458,821 $ 391,267 _________________ (a) Includes accruals for property, plant and equipment. Property, Plant and Equipment as of December 31, 2015 2014 Utilities: Electric Utilities (a) $ 2,769,547 $ 2,597,212 Gas Utilities 741,520 687,665 Non-regulated Energy: Power Generation (a) 158,903 156,041 Coal Mining 158,279 149,367 Oil and Gas 1,132,776 962,395 Corporate 15,753 10,720 Total property, plant and equipment $ 4,976,778 $ 4,563,400 _______________ (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, 2015 Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 712,387 $ 507,139 $ 7,483 $ 34,313 $ 43,283 $ — $ — $ 1,304,605 Inter-company revenue 11,617 — 83,307 30,753 — 227,708 (353,385 ) — Total revenue 724,004 507,139 90,790 65,066 43,283 227,708 (353,385 ) 1,304,605 Fuel, purchased power and cost of natural gas sold 291,563 277,491 — — — 122 (112,289 ) 456,887 Operations and maintenance 173,810 127,837 32,140 41,630 41,593 225,721 (229,786 ) 412,945 Depreciation, depletion and amortization 84,284 28,971 4,329 9,806 29,287 9,273 (10,580 ) 155,370 Impairment of long-lived assets (a) — — — — 249,608 — — 249,608 Operating income (loss) 174,347 72,840 54,321 13,630 (277,205 ) (7,408 ) (730 ) 29,795 Interest expense (57,712 ) (15,359 ) (4,218 ) (433 ) (2,726 ) (57,839 ) 54,568 (83,719 ) Interest income 4,236 479 1,015 34 217 48,582 (52,942 ) 1,621 Other income (expense), net 1,225 532 71 2,247 (337 ) 70,889 (72,190 ) 2,437 Impairment of equity investments (a) — — — — (4,405 ) — — (4,405 ) Income tax benefit (expense) (42,792 ) (20,685 ) (18,539 ) (3,608 ) 104,498 2,926 360 22,160 Income (loss) from continuing operations $ 79,304 $ 37,807 $ 32,650 $ 11,870 $ (179,958 ) $ 57,150 $ (70,934 ) $ (32,111 ) ________________ (a) Oil and Gas includes ceiling test and equity investment impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2014 Electric Utilities Gas Utilities Power Generation 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 24,246 7,690 (7,930 ) 144,745 Operating income (loss) 137,673 77,782 49,892 11,910 (11,791 ) 1,239 (2,837 ) 263,868 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 ) 4,768 24 744 (66,625 ) Income (loss) from continuing operations $ 59,552 $ 41,869 $ 28,516 $ 10,452 $ (8,525 ) $ 61,538 $ (62,513 ) $ 130,889 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 17,877 11,624 (12,876 ) 137,324 Operating income (loss) 133,595 76,772 47,760 5,586 (3,358 ) 6,062 (6,972 ) 259,445 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 ) 2,113 (7,778 ) 218 (63,040 ) Income (loss) from continuing operations $ 52,134 $ 32,707 $ 16,288 $ 6,327 $ (1,751 ) $ 54,471 $ (41,869 ) $ 118,307 ________________ (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.

Long-Term Debt_

Long-Term Debt:	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Long-term Debt	LONG-TERM DEBT Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Due Date December 31, 2015 December 31, 2015 December 31, 2014 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,890 ) (2,164 ) Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Corporate term loan due 2017 (a) April 12, 2017 1.28% 300,000 — Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 — Corporate term loan due 2015 (a) June 19, 2015 1.31% — 275,000 Total Corporate Debt 1,322,110 997,836 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (99 ) (102 ) First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 0.05% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 0.05% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 0.75% 2,855 2,855 Total Electric Utilities Debt 544,756 544,753 Total long-term debt 1,866,866 1,542,589 Less current maturities — 275,000 Long-term debt, net of current maturities $ 1,866,866 $ 1,267,589 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (c) Variable interest rate. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2016 $ — 2017 $ 300,000 2018 $ — 2019 $ — 2020 $ 200,000 Thereafter $ 1,368,855 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2015 . 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. Corporate Term Loan On April 13, 2015, we entered into a new $300 million Corporate term loan due April 12, 2017 . This new term loan replaced the $275 million Corporate term loan due on June 19, 2015 and was classified as Long-Term Debt as of December 31, 2015. The additional $25 million , less interest and fees, was used for general corporate purposes. The cost of the borrowing under the new term loan is LIBOR plus a margin of 0.9% . The covenants on the new term loan are substantially the same as the Revolving Credit Facility. Amortization Expense Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Senior unsecured notes due 2023 $ 3,414 $ 494 $ 653 $ 86 Senior unsecured notes due 2014 — — — 635 Senior unsecured notes due 2020 759 167 167 167 Bridge Term Loan 843 4,213 — — RSNs due 2028 1,567 10 — — First mortgage bonds due 2044 (Black Hills Power) (a) 687 24 6 — First mortgage bonds due 2044 (Cheyenne Light) (a) 635 22 6 — First mortgage bonds due 2032 551 33 33 33 First mortgage bonds due 2039 1,809 76 76 76 First mortgage bonds due 2037 674 31 31 31 Black Hills Wyoming project financing due 2016 (b) — — — 3,177 Other 440 43 53 57 Total $ 11,379 $ 5,113 $ 1,025 $ 4,262 _____________ (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 when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2015 , 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, 2015 : • 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, 2015 , the restricted net assets at our Utilities Group were approximately $316 million .

Notes Payable_

Notes Payable:	12 Months Ended
	Dec. 31, 2015
Notes Payable [Abstract]
Notes Payable	NOTES PAYABLE Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2015 , 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 December 31, 2015 December 31, 2014 Revolving Credit Facility $ 76,800 $ 75,000 Revolving Credit Facility On June 26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through June 26, 2020 . This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million . Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P and 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. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating. As of December 31, 2015 and 2014 , we had outstanding letters of credit totaling approximately $33 million and approximately $35 million , respectively. Deferred financing costs on the facility of $4.3 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income (Loss). The deferred financing costs on the new facility are being amortized as follows (in thousands): Deferred Financing Costs Remaining on Balance Sheet as of Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Revolving Credit Facility $ 1,705 $ 504 $ 616 $ 752 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, 2015 Covenant Requirement Recourse leverage ratio 60 % Less than 65 %

Asset Retirement Obligations_

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2015
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): December 31, 2014 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) December 31, 2015 Electric Utilities $ 7,012 $ — $ (2,733 ) $ 183 $ — $ 4,462 Gas Utilities 291 — (168 ) 13 — 136 Coal Mining 19,138 — — 993 (1,498 ) 18,633 Oil and Gas 20,945 828 (1,792 ) 1,371 152 21,504 Total $ 47,386 $ 828 $ (4,693 ) $ 2,560 $ (1,346 ) $ 44,735 December 31, 2013 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a)(b) December 31, 2014 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 _____________________ (a) The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions. (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, 2015
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, 2015 , our credit exposure included a $1.1 million exposure to a non-investment grade rural electric cooperative. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10 . Oil and Gas 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: December 31, 2015 December 31, 2014 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) 198,000 4,392,500 334,500 6,582,500 Maximum terms in months (b) 1 1 1 1 Derivative assets, current $ — $ — $ — $ — Derivative assets, non-current $ — $ — $ — $ — Derivative liabilities, current $ — $ — $ — $ — Derivative liabilities, non-current $ — $ — $ — $ — ________________________ (a) Crude in Bbls, gas in MMBtu’s. (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, 2015 market prices, a $10 million gain would be reclassified from AOCI during 2016 . 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: December 31, 2015 December 31, 2014 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 20,580,000 60 19,370,000 72 Natural gas options purchased 2,620,000 3 4,020,000 8 Natural gas basis swaps purchased 18,150,000 60 12,005,000 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): December 31, 2015 December 31, 2014 Derivative assets, current $ — $ — Derivative assets, non-current $ — $ — Derivative liabilities, current $ — $ — Derivative liabilities, non-current $ — $ — Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities $ 23,578 $ 18,740 Financing Activities We entered into pay-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations and anticipated debt refinancings. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2015 December 31, 2015 December 31, 2014 Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (a) Notional $ 75,000 $ 250,000 $ 75,000 Weighted average fixed interest rate 4.97 % 2.29 % 4.97 % Maximum terms in years 1.0 1.3 2.0 Derivative assets, non-current $ — $ 3,441 $ — Derivative liabilities, current $ 2,835 $ — $ 3,340 Derivative liabilities, non-current $ 156 $ — $ 2,680 ___________________ (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. (b) These swaps are designated as cash flow hedges of anticipated debt refinancings. Based on December 31, 2015 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $2.8 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): December 31, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ 2,888 Interest expense $ 3,647 $ — Commodity derivatives 9,782 Revenue (14,460 ) — Total $ 12,670 $ (10,813 ) $ — December 31, 2014 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (536 ) Interest expense $ 3,669 $ — Commodity derivatives 14,681 Revenue 1,995 — Total $ 14,145 $ 5,664 $ — December 31, 2013 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ 7,935 Interest expense $ 6,989 $ — Commodity derivatives (956 ) Revenue (927 ) — Total $ 6,979 $ 6,062 $ — 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): 2015 2014 2013 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 Interest rate swaps - realized (a) Interest expense — — (12,902 ) $ — $ — $ 17,267 _______________ (a) These interest rate swaps were settled in the fourth quarter of 2013.

Fair Value Measurements_

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2015
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 2015 or 2014 . Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. A discussion of fair value of financial instruments is included in Note 11 . The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas: Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 6,309 — (6,309 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,335 — (4,335 ) — Commodity derivatives - Utilities — 2,293 — (2,293 ) — Interest rate swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives - Oil and Gas: Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 556 — (556 ) — Commodity derivatives - Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of 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 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, 2015 and 2014 , 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 9 . The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): 2015 2014 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 $ 9,981 $ — $ 10,391 $ — Commodity derivatives Derivative assets - non-current 663 — 4,766 — Interest rate swaps Derivative assets - non-current 3,441 — — — Commodity derivatives Derivative liabilities - current — 465 — 185 Commodity derivatives Derivative liabilities - non-current — 91 — 288 Interest rate swaps Derivative liabilities - current — 2,835 — 3,340 Interest rate swaps Derivative liabilities - non-current — 156 — 2,680 Total derivatives designated as hedges $ 14,085 $ 3,547 $ 15,157 $ 6,493 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ — $ — $ — $ — Commodity derivatives Derivative assets - non-current — — — — Commodity derivatives Derivative liabilities - current — 9,586 — 8,032 Commodity derivatives Derivative liabilities - non-current — 12,706 — 8,882 Interest rate swaps Derivative liabilities - current — — — — Interest rate swaps Derivative liabilities - non-current — — — — Total derivatives not designated as hedges $ — $ 22,292 $ — $ 16,914 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, 2015 and December 31, 2014 , 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, 2015 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 $ 6,309 $ (6,309 ) $ — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps 4,335 (4,335 ) — Utilities 2,293 (2,293 ) — Interest Rate Swaps 3,441 — 3,441 Total derivative assets subject to a master netting agreement or similar arrangement 16,378 (12,937 ) 3,441 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps — — — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps — — — Utilities — — — Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement — — — Total derivative assets $ 16,378 $ (12,937 ) $ 3,441 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps $ — $ — $ — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps 556 (556 ) — Utilities 24,585 (24,585 ) — Interest Rate Swaps 2,991 — 2,991 Total derivative liabilities subject to a master netting agreement or similar arrangement 28,132 (25,141 ) 2,991 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps — — — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps — — — Utilities — — — Interest Rate Swaps — — — Total derivative liabilities not subject to a master netting agreement or similar arrangement — — — Total derivative liabilities $ 28,132 $ (25,141 ) $ 2,991 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2014 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 $ 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 Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2015 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 — — — Interest Rate Swaps Counterparty G 3,441 — 3,441 $ 3,441 $ — $ 3,441 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 $ — $ (1,672 ) $ (1,672 ) Oil and Gas Counterparty B — — — Utilities Counterparty A — (5,367 ) (5,367 ) Interest Rate Swaps Counterparty F 2,991 — 2,991 $ 2,991 $ (7,039 ) $ (4,048 ) 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 Swap Counterparty F 6,020 — 6,020 $ 6,020 $ (7,485 ) $ (1,465 )

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments:	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 456,535 $ 456,535 $ 21,218 $ 21,218 Restricted cash and equivalents (a) $ 1,697 $ 1,697 $ 2,056 $ 2,056 Notes payable (a) $ 76,800 $ 76,800 $ 75,000 $ 75,000 Long-term debt, including current maturities (b) $ 1,866,866 $ 1,992,274 $ 1,542,589 $ 1,734,555 _______________ (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 6 and Note 7 .

Stock_

Stock:	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Stock	STOCK Equity Units On November 23, 2015, we issued 5.98 million equity units for total gross proceeds of $299 million . Each Equity Unit has a stated amount of $50 and consists of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5% , undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. The RSNs, a debt instrument, and the forward purchase contracts, an equity instrument, are deemed to be separate instruments as the investor may trade the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately. The forward purchase contracts obligate the holders to purchase from the Company on the settlement date, which shall be no later than November 1, 2018, for a price of $50 in cash, the following number of shares of our common stock, subject to anti-dilution adjustments: • if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938 , 1.0572 shares of the Company’s common stock per Equity Unit; • if the AMV is less than $47.2938 but greater than $40.25 , a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50 ; and • if the AMV is less than or equal to $40.25 , 1.2422 shares of the Company’s common stock. The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing, the interest rate on the RSNs will not be reset, and the holders of the RSNs will have the right to put the RSNs to the Company at a price equal to 100% of the principal amount, and the proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts. The Company will also pay the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million , is recorded as a reduction of shareholders’ equity. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2015, the forward purchase contracts were not dilutive and therefore not included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders. Selected information about our equity units is presented below (in thousands except for percentages) : Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 33,118 Common Stock Offering On November 23, 2015, we issued 6.325 million shares of Common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million . The proceeds from the offering were used to partially fund the purchase of SourceGas, which closed on February 12, 2016. Equity Compensation Plans Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 1,256,747 shares available to grant at December 31, 2015 . 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, 2015 , total unrecognized compensation expense related to non-vested stock awards was approximately $7.7 million and is expected to be recognized over a weighted-average period of 1.7 years . Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands): 2015 2014 2013 Stock-based compensation expense $ 4,076 $ 9,329 $ 12,595 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, 2015 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 134 $ 46.12 Granted — — Forfeited/canceled (5 ) 54.29 Expired — — Exercised — — Balance at end of period 129 $ 45.80 7.0 $ 678 Exercisable at end of period 75 $ 40.29 6.3 $ 658 The table below provides details of our option plans at December 31 (in thousands): 2015 2014 2013 Summary of Stock Options Unrecognized compensation expense $ 425 $ 816 $ 130 Intrinsic value of options exercised (a) $ — $ 199 $ 789 Net cash received from exercise of options $ — $ 237 $ 2,046 Tax benefit realized from exercise of shares (b) $ — $ 70 $ 276 _____________________ (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, 2015 , the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 1.1 years . Restricted Stock The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years , contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2015 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 233 $ 44.60 Granted 107 50.01 Vested (120 ) 41.39 Forfeited (18 ) 49.00 Balance at end of period 202 $ 48.96 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) 2015 $ 50.01 $ 6,009 2014 $ 54.34 $ 6,114 2013 $ 40.56 $ 5,842 As of December 31, 2015 , there was $6.0 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.8 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 $2.2 million at December 31, 2015 would be reclassified as a liability. Outstanding performance periods at December 31 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2013 January 1, 2013 - December 31, 2015 61 0% 200% January 1, 2014 January 1, 2014 - December 31, 2016 44 0% 200% January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2015 (in thousands) (in thousands) Performance Shares balance at beginning of period 84 $ 39.58 84 Granted 22 54.92 22 Forfeited — — — Vested (32 ) 32.26 (32 ) Performance Shares balance at end of period 74 $ 31.21 74 $ 4.55 _____________________ (a) The grant date fair values for the performance shares granted in 2015 , 2014 and 2013 were determined by Monte Carlo simulation using a blended volatility of 21% , 23% and 20% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows: Weighted Average Grant Date Fair Value December 31, 2015 $ 54.92 December 31, 2014 $ 55.18 December 31, 2013 $ 35.85 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, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314 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 On January 26, 2016 , the Compensation Committee of our Board of Directors determined that the Company’s performance criteria for the January 1, 2013 through December 31, 2015 performance period was not met. As a result, there will be no payout for this period. As of December 31, 2015 , there was $1.3 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 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): 2015 2014 Shares Issued 66 52 Weighted Average Price $ 44.79 $ 54.99 Unissued Shares Available 408 474 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 Assets_

Impairment Of Assets:	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Impairment of Assets	IMPAIRMENT OF ASSETS Long-lived assets Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. As a result of continued low commodity prices throughout 2015, we have recorded a non-cash impairment of oil and gas assets included in the Oil and Gas segment totaling approximately $250 million for the year ended December 31, 2015. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead. Equity investments in unconsolidated subsidiaries Our Oil and Gas segment owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, due to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements . We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss at June 30, 2015 of $5.2 million , the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system at a price exceeding our book value and recorded a pre-tax gain of approximately $0.8 million .

Operating Leases_

Operating Leases:	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Rent expense $ 7,177 $ 6,932 $ 7,169 The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2016 $ 2,907 2017 $ 2,491 2018 $ 2,268 2019 $ 1,932 2020 $ 1,238 Thereafter $ 6,199

Income Taxes_

Income Taxes:	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2015 2014 2013 Current: Federal $ 2,549 $ (2,319 ) $ (2,003 ) State 1,319 (1,288 ) (173 ) 3,868 (3,607 ) (2,176 ) Deferred: Federal (23,592 ) 64,780 58,288 State (2,323 ) 5,658 7,140 Tax credit amortization (113 ) (206 ) (212 ) (26,028 ) 70,232 65,216 $ (22,160 ) $ 66,625 $ 63,040 The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2015 2014 Deferred tax assets: Regulatory liabilities $ 43,586 $ 49,243 Employee benefits 26,400 26,714 Federal net operating loss 217,922 213,466 Asset impairment (a) 181,731 93,663 Other deferred tax assets (b) 85,907 76,005 Less: Valuation allowance (4,304 ) (5,017 ) Total deferred tax assets 551,242 454,074 Deferred tax liabilities: Accelerated depreciation, amortization and other plant-related differences (709,068 ) (695,280 ) Regulatory assets (29,092 ) (25,340 ) Mining development and oil exploration (183,956 ) (109,571 ) State deferred tax liability (35,065 ) (36,579 ) Deferred costs (26,121 ) (35,284 ) Other deferred tax liabilities (18,519 ) (15,684 ) Total deferred tax liabilities (1,001,821 ) (917,738 ) Net deferred tax liability $ (450,579 ) $ (463,664 ) _______________ (a) Majority of impairment deferred tax asset is related to oil and gas properties. (b) 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: 2015 2014 2013 Federal statutory rate (35.0 )% 35.0 % 35.0 % State income tax (net of federal tax effect) (1.0 ) 1.1 2.4 Amortization of excess deferred income taxes and investment tax credits (0.2 ) (0.1 ) (0.1 ) Percentage depletion in excess of cost (a) (3.5 ) (1.0 ) (0.9 ) Equity AFUDC (0.3 ) (0.1 ) — Tax credits (0.5 ) (0.1 ) (0.5 ) Accounting for uncertain tax positions adjustment (b) 3.5 (0.1 ) 0.7 Flow-through adjustments (c) (3.8 ) (0.9 ) (0.9 ) Other tax differences — (0.1 ) (0.9 ) (40.8 )% 33.7 % 34.8 % _________________________ (a) The tax benefit has remained relatively the same for each period presented, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015. (b) The tax expense recorded in 2015 included the re-measurement related to research and development credits and deductions, which increased tax expense. The combination of the re-measurement, continued accrual of after-tax interest expense associated with other uncertain tax positions primarily the like-kind exchange transaction, and pre-tax net loss resulted in a greater impact on the effective tax rate in 2015. (c) 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. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015. At December 31, 2015 , 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 $ 624,218 2019 to 2035 State Net Operating Loss Carryforward $ 463,679 2015 to 2035 As of December 31, 2015 , we had a $0.8 million valuation allowance against the state NOL carryforwards. Our 2015 analysis of the ability to utilize such NOLs resulted in a slight decrease of the valuation allowance of approximately $0.2 million , which resulted in a decrease to tax expense. The valuation allowance adjustment was primarily attributable to a projected increase in state taxable income for years beyond 2015. Such an increase 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, 2013 $ 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 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 $ 31,986 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $2.6 million . We recognized interest expense of $1.8 million , $1.6 million and $1.6 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. We had approximately $13.3 million and $11.5 million of accrued interest (before tax effect) associated with income taxes at December 31, 2015 and 2014 , 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; however in February 2016, we reached an agreement in principle with IRS Appeals and expect a reduction of approximately $21 million with respect to our liability for unrecognized tax benefits on or before December 31, 2016. Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2015 , we had foreign tax credit carryforwards of approximately $0.5 million , which expire between 2015 and 2017 . As of December 31, 2015 , 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, 2015 , 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, 2015 , we had a $3.0 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in a decrease of the valuation allowance of approximately $0.5 million of which approximately $0.3 million resulted in a decrease to tax expense. The remaining $0.2 million decrease is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of greater projected apportionment factors resulting in increased state taxable income in years beyond 2015. 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, 2015
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 (Loss) Amount Reclassified from AOCI December 31, 2015 December 31, 2014 Gains and losses on cash flow hedges: Interest rate swaps Interest expense $ 3,647 $ 3,669 Commodity contracts Revenue (14,460 ) 1,995 (10,813 ) 5,664 Income tax Income tax benefit (expense) 4,271 (2,344 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (6,542 ) $ 3,320 Amortization of defined benefit plans: Prior service cost Utilities - Operations and maintenance $ (106 ) $ (102 ) Non-regulated energy operations and maintenance (132 ) (115 ) Actuarial gain (loss) Utilities - Operations and maintenance 1,816 630 Non-regulated energy operations and maintenance 1,006 364 2,584 777 Income tax Income tax benefit (expense) (884 ) (272 ) Total reclassification adjustments related to defined benefit plans, net of tax $ 1,700 $ 505 Balances by classification included within AOCI 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, 2014 $ (4,930 ) $ 10,023 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss) 4,589 (2,957 ) 4,357 5,989 As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) 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 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash flow Information:	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Years ended December 31, 2015 2014 2013 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 40,250 $ 52,584 $ 59,811 Increase (decrease) in capitalized assets associated with asset retirement obligations $ (518 ) $ (5,634 ) $ 1,235 Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (77,810 ) $ (69,239 ) $ (108,361 ) Income taxes, net $ (1,202 ) $ (413 ) $ (4,573 )

Employee Benefit Plans_

Employee Benefit Plans:	12 Months Ended
	Dec. 31, 2015
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 AOCI, 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, 2015 . As of December 31, 2015 , the unfunded status of our Defined Benefit Pension Plans was $68 million ; the unfunded status of our Supplemental Non-qualified Defined Benefit Plans was $40 million ; and the unfunded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $43 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 closed 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% for the 2015 and 2014 plan years, respectively. Our Pension Plan funding policy is in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows: 2015 2014 Equity 26% 27% Real estate 5 5 Fixed income 59 58 Cash 1 2 Hedge funds 9 8 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 is 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): 2015 2014 Defined Contribution Plan Company Retirement Contribution $ 5,564 $ 4,187 Matching contributions - Defined Contribution Plans $ 9,616 $ 9,254 2015 2014 Defined Benefit Plans Defined Benefit Pension Plans $ 10,200 $ 10,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 3,771 $ 3,163 Supplemental Non-Qualified Defined Benefit Plans $ 1,564 $ 1,553 While we do not have required contributions, we expect to make approximately $10 million in contributions to our Defined Benefit Pension Plans in 2016 . 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 December 31, 2015 Level 1 Level 2 Level 3 Total AXA Equitable General Fixed Income $ — $ 1,072 $ — $ 1,072 Common Collective Trust - Cash and Cash Equivalents — 1,556 — 1,556 Common Collective Trust - Equity — 74,885 — 74,885 Common Collective Trust - Fixed Income — 172,016 — 172,016 Common Collective Trust - Real Estate — 2,204 11,143 13,347 Hedge Funds — — 25,746 25,746 Total investments measured at fair value $ — $ 251,733 $ 36,889 $ 288,622 Defined Benefit Pension Plans December 31, 2014 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 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2015 Level 1 Level 2 Level 3 Total Registered Investment Company Trust - Money Market Mutual Fund $ — $ 4,681 $ — $ 4,681 Total investments measured at fair value $ — 4,681 $ — $ 4,681 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2014 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 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): 2015 2014 Balance, beginning of period $ 34,753 $ 38,188 Purchase 491 454 Unrealized gain (loss) 1,644 1,789 Realized gain (loss) 1 322 Settlements — (6,000 ) Balance, end of period $ 36,889 $ 34,753 The following table presents the quantitative information about Level 3 fair value measurements (dollars in thousands): Fair Value at Valuation Level 3 Range (Weighted) December 31, 2015 Technique Input Average Assets: Common Collective Trust - Real Estate (a) $ 11,143 Market Approach Redemption Restriction N/A Hedge Funds (b) $ 25,746 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 AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans 2015 2014 2015 2014 2015 2014 Change in benefit obligation: Projected benefit obligation at beginning of year $ 377,772 321,400 $ 41,211 $ 32,960 $ 49,042 $ 45,778 Service cost 6,093 5,448 1,300 2,543 1,808 1,700 Interest cost 15,522 15,852 1,455 1,447 1,801 1,919 Actuarial (gain) loss (a) (28,229 ) 55,384 (2,072 ) 5,814 (1,206 ) 2,275 Benefits paid (b) (14,583 ) (20,312 ) (1,675 ) (1,553 ) (3,771 ) (3,163 ) Medicare Part D accrued — — — — (178 ) (99 ) Plan participants’ contributions — — — — 581 632 Projected benefit obligation at end of year $ 356,575 $ 377,772 $ 40,219 $ 41,211 $ 48,077 $ 49,042 ____________________ (a) Change from 2014 reflects an increase in the discount rate and a change in the mortality tables used in employee benefit plan estimates. (b) Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings. 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) 2015 2014 2015 2014 2015 2014 Beginning market value of plan assets $ 299,533 $ 280,362 $ — $ — $ 4,705 $ 4,546 Investment income (loss) (6,528 ) 29,283 — — (9 ) (43 ) Employer contributions 10,200 10,200 — — 3,175 2,733 Retiree contributions — — — — 581 632 Benefits paid (14,583 ) (20,312 ) (b) — — (3,771 ) (3,163 ) Plan administrative expenses — — — — — — Ending market value of plan assets $ 288,622 $ 299,533 $ — $ — $ 4,681 $ 4,705 ____________________ (a) Assets of VEBA. (b) Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings. 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 2015 2014 2015 2014 2015 2014 Regulatory assets $ 68,915 $ 78,864 $ — $ — $ 6,464 $ 7,137 Current liabilities $ — $ — $ 1,568 $ 1,486 $ 3,543 $ 3,273 Non-current assets $ — $ — $ — $ — $ 23 $ — Non-current liabilities $ 67,953 $ 78,239 $ 38,651 $ 39,725 $ 39,855 $ 41,002 Regulatory liabilities $ — $ — $ — $ — $ 3,209 $ 2,983 Accumulated Benefit Obligation (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2015 2014 2015 2014 2015 2014 Accumulated benefit obligation - Black Hills Corporation $ 129,729 $ 135,582 $ 30,207 $ 29,843 $ 13,121 $ 12,809 Accumulated benefit obligation - Black Hills Energy 205,194 213,398 351 386 23,796 25,456 Accumulated benefit obligation - Cheyenne Light — — — — 11,160 10,777 Total Accumulated Benefit Obligation $ 334,923 $ 348,980 $ 30,558 $ 30,229 $ 48,077 $ 49,042 Components of Net Periodic Expense (in thousands) Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2015 2014 2013 2015 2014 2013 2015 2014 2013 Service cost $ 6,093 $ 5,448 $ 6,433 $ 1,380 $ 1,498 $ 1,392 $ 1,808 $ 1,700 $ 1,674 Interest cost 15,522 15,852 15,300 1,455 1,447 1,328 1,801 1,919 1,669 Expected return on assets (19,470 ) (18,065 ) (18,615 ) — — — (131 ) (85 ) (79 ) Amortization of prior service cost 58 62 63 2 2 2 (428 ) (428 ) (500 ) Recognized net actuarial loss (gain) 11,037 4,806 12,250 1,081 498 793 408 160 482 Net periodic expense $ 13,240 $ 8,103 $ 15,431 $ 3,918 $ 3,445 $ 3,515 $ 3,458 $ 3,266 $ 3,246 AOCI In accordance with accounting standards for defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2015 2014 2015 2014 2015 2014 Net (gain) loss $ 8,777 $ 10,996 $ 6,339 $ 8,396 $ 1,704 $ 1,904 Prior service cost (gain) 41 51 6 8 (1,087 ) (1,218 ) Total AOCI $ 8,818 $ 11,047 $ 6,345 $ 8,404 $ 617 $ 686 The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2016 are as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 4,663 $ 539 $ 221 Prior service cost (credit) 38 1 (278 ) Total net periodic benefit cost expected to be recognized during calendar year 2016 $ 4,701 $ 540 $ (57 ) 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: 2015 2014 2013 2015 2014 2013 2015 2014 2013 Discount rate 4.59 % 4.20 % 5.05 % 3.92 % 3.64 % 4.21 % 4.26 % 3.92 % 4.62 % Rate of increase in compensation levels 3.52 % 3.78 % 3.78 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2015 2014 2013 2015 2014 2013 2015 2014 2013 Discount rate: Black Hills Corporation 4.25 % 5.10 % 4.35 % 3.98 % 4.68 % 3.88 % 3.70 % 4.45 % 3.65 % Black Hills Energy 4.15 % 5.00 % 4.25 % 3.30 % 3.75 % 3.00 % 3.65 % 4.25 % 3.50 % Cheyenne Light N/A N/A N/A N/A N/A N/A 4.40 % 5.15 % 4.40 % Expected long-term rate of return on assets (a) 6.75 % 6.75 % 7.25 % N/A N/A N/A 3.00 % 2.00 % 2.00 % Rate of increase in compensation levels 3.78 % 3.78 % 3.78 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: Black Hills Corporation Black Hills Energy Cheyenne Light 2015 Healthcare trend rate pre-65 Trend for next year 6.35 % 6.35 % 6.35 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2024 2024 2024 Healthcare trend rate post-65 Trend for next year 5.20 % 5.20 % 5.20 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2023 2023 2023 2014 Healthcare trend rate pre-65 Trend for next year 7.50 % 7.50 % 7.50 % Ultimate trend rate 4.50 % 4.50 % 4.50 % 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 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2024 2024 2024 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, 2015 Accumulated Postretirement Benefit Obligation Impact on 2015 Service and Interest Cost Increase 1% $ 2,471 $ 173 Decrease 1% $ (2,088 ) $ (141 ) Beginning in 2016, the Company will change the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. The new method uses the spot yield curve approach to estimate the service and interest costs by applying the specific spot rates along the yield curve used to determine the benefit obligations to relevant projected cash outflows. Previously, those costs were determined using a single weighted-average discount rate. The change does not affect the measurement of the total benefit obligations as the change in service and interest costs offsets the actuarial gains and losses recorded in other comprehensive income. The new method provides a more precise measure of interest and service costs by improving the correlation between the projected benefit cash flows and the discrete spot yield curve rates. The Company will account for this change as a change in estimate prospectively beginning in the first quarter of 2016. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details. The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plan Non-Pension Defined Benefit Postretirement Healthcare Plans 2016 $ 15,700 $ 1,568 $ 4,270 2017 $ 16,666 $ 1,628 $ 4,337 2018 $ 17,620 $ 1,682 $ 4,331 2019 $ 18,809 $ 1,808 $ 4,309 2020 $ 19,764 $ 1,539 $ 4,292 2021-2025 $ 113,480 $ 10,024 $ 19,552

Commitments And Contingencies_

Commitments And Contingencies:	12 Months Ended
	Dec. 31, 2015
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, 2016 , which provides for the purchase of 50 MW energy during heavy 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): 2015 2014 2013 PPA with PacifiCorp $ 13,990 $ 13,943 $ 13,026 Transmission services agreement with PacifiCorp $ 1,213 $ 1,227 $ 1,384 PPA with Happy Jack $ 3,155 $ 3,919 $ 3,772 PPA with Silver Sage $ 4,107 $ 4,798 $ 4,809 Busch Ranch Wind Project $ 1,734 $ 1,998 $ 1,856 PPAs with Cargill $ 16,112 $ 9,286 $ 12,291 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 10 year agreement expiring in 2024 became effective in first quarter of 2014 upon completion of the processing infrastructure capable of handling the committed volumes. 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): 2016 $ 165,484 2017 $ 133,534 2018 $ 82,703 2019 $ 49,196 2020 $ 48,966 Thereafter $ 130,745 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. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties: • During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. • 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 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. Build Transfer Agreement On November 2, 2015, Colorado Electric executed a build-transfer agreement with Invenergy Wind Development Colorado, LLC to purchase the 60 MW, $109 million Peak View Wind Project. Peak View will be built by Invenergy Wind Development Colorado, LLC approximately 30 miles south of Pueblo, Colorado, in Huerfano and Las Animas counties. The estimated cost of $109 million includes taxes, transmission infrastructure and interconnection costs. Construction is expected to start in the spring of 2016, and be completed in late 2016. Under the build transfer agreement, Colorado Electric will make progress payments starting in late 2015, continuing through completion of the project. Ownership of Peak View will transfer prior to commercial operation to Colorado Electric and will be operated as a utility-owned asset. BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric. At December 31, 2015, BHC’s guarantee was approximately $90 million . The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. 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, SO 2 , NO x , mercury, hazardous air pollutants, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies. Title IV of the Clean Air Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT, Lange CT, Wygen I, Wygen II, Wygen III, Wyodak and Pueblo Airport Generating Station plants. Title IV of the Clean Air Act created an SO 2 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 2045. 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 8 for additional information. Manufactured Gas Processing As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.4 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. We have not yet received state approval for “no further action”. In late 2015, groundwater concentrations were proposed and approved by the Nebraska Department of Environmental Quality as meeting steady or declining pollution levels. We assembled our final removal action completion reports to formally close the site, and submitted reports to the Nebraska Department of Environmental Quality in December 2015. As of December 31, 2015, our estimated liabilities for all of the MGP sites currently range from approximately $2.9 million to $6.1 million for which we had $2.6 million accrued for remediation of sites as of December 31, 2015 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. On April 16, 2013, private landowners filed suit in the United States District Court for the District of Wyoming asserting that the fire was caused by Black Hills Power’s negligent maintenance of a transmission line. The Company denied these claims. These landowners sought recovery for 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. The State of Wyoming intervened in the lawsuit, asserting claims for fire suppression costs, and similar damage claims related to state-owned lands. As of December 31, 2015, we believed that a loss associated with settlement of pending claims was probable. Accordingly, we had recorded a loss contingency liability related to these claims and a receivable for costs we believed were reimbursable and probable of recovery under our insurance coverage. In consideration of the risk and uncertainty of litigation, the Company subsequently concluded a settlement of all claims, with all parties to the litigation. On January 4, 2016, the court entered its order dismissing the litigation with prejudice. The resolution of the State and private claims did not have a material effect upon our consolidated financial condition, results of operations or cash flows.

Guarantees_

Guarantees:	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Guarantees	GUARANTEES We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2015 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 69,773 Ongoing Contract performance guarantee (b) 89,718 December, 2016 $ 159,491 _______________________ (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. (b) BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements. SourceGas Guarantee On July 12, 2015 Black Hills Utility Holdings entered into a definitive agreement to acquire SourceGas from funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) for approximately $1.89 billion . As part of the executed purchase and sale agreement, BHC guaranteed the full and complete payment and performance of Black Hills Utility Holdings. This guarantee expired upon the closing of the SourceGas Acquisition on February 12, 2016.

Oil and Gas Reserves (Unaudited

Oil and Gas Reserves (Unaudited):	12 Months Ended
	Dec. 31, 2015
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 1,006 gross developed oil and gas wells in 10 states and holds leases on approximately 236,545 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): 2015 2014 2013 Acquisition of properties: Proved $ 1,407 $ 4,881 $ 234 Unproved 669 5,056 6,022 Exploration costs 35,434 54,355 12,817 Development costs 128,998 52,262 48,641 Asset retirement obligations incurred 566 68 143 Total costs incurred $ 167,074 $ 116,622 $ 67,857 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, 2015 , 2014 and 2013 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. 2015 2014 2013 Oil Gas NGL Oil Gas NGL Oil Gas (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 4,276 65,440 1,720 3,921 63,190 — 4,116 55,985 Production (a) (371 ) (10,058 ) (102 ) (337 ) (7,156 ) (135 ) (336 ) (6,984 ) Additions - acquisitions (sales) (11 ) (828 ) — (40 ) (61 ) — (30 ) (46 ) Additions - extensions and discoveries 199 24,462 232 733 11,003 182 379 10,456 Revisions to previous estimates (643 ) (5,604 ) (98 ) (1 ) (1,536 ) 1,673 (208 ) 3,779 Balance at end of year 3,450 73,412 1,752 4,276 65,440 1,720 3,921 63,190 Proved developed reserves at end of year included above 3,436 73,390 1,752 3,780 57,427 1,530 3,689 60,224 Proved undeveloped reserves at the end of year included in above 14 22 — 496 8,013 191 232 2,966 NYMEX prices $ 50.28 $ 2.59 $ — (b) $ 94.99 $ 4.35 $ — (b) $ 96.94 $ 3.67 Well-head reserve prices $ 44.72 $ 1.27 $ 18.96 $ 85.80 $ 3.33 $ 34.81 $ 89.79 $ 3.45 ________________________ (a) Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production. Reserve additions for 2015 totaled 27.0 Bcfe, replacing 209% of annual production. Reserve additions resulted from drilling in the Piceance and Powder River Basins. Drilling in the Piceance for Mancos Shale accounted for 25.9 Bcfe and Powder River Basin drilling accounted for 1.2 Bcfe. Capital spending in 2015 was primarily for drilling and completion activities in the Piceance Basin. Future capital spending rates will be dependent on product prices, processing availability and support of our Cost of Service Gas program. In 2015 , we had negative revisions of ( 10.1 Bcfe) to previous reserve estimates. Most of the negative revision was the result of lower equivalent prices of oil, liquids and gas received at the wellhead of ( 20.1 Bcfe), partially offset by improved wellhead performance of 3.6 Bcfe and non-consent interests we assumed related to new wells drilled in the southern Piceance Basin of 6.9 Bcfe. We changed our process for reporting natural gas in 2014 to separate NGL from wet gas steam. This change was from increased NGL recovery from the Powder River Finn Field and the Piceance wells. 2013 NGL was reported wet. 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. SEC regulations require that proved undeveloped (PUD) locations meet the test of being developed within five years of being categorized as proved. In 2015 , 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. • The decrease in 2015 of 28 PUD locations is driven by low commodity prices and economics. The remaining six PUD locations are in the Williston Basin and require approximately $0.4 million of future investment. • Due to economic conditions in 2015, no new gross PUD locations were added for future drilling in the Williston Bakken, Piceance Mancos or Powder River Basin. • The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2015 were: Proved Reserves (in Bcfe) Gross PUD Locations Future Development Costs (in millions) Existing 2014: Williston 1.1 30 $ 5.4 Piceance 9.0 3 $ 23.5 Powder River 2.0 1 $ 13.0 Year End Total 2014 12.1 34 $ 41.9 Dropped 2015: Williston (1.0 ) (21 ) $ (4.6 ) Piceance (4.4 ) (1 ) $ (11.5 ) (5.4 ) (22 ) $ (16.1 ) Drilled in 2015: Williston — (3 ) $ (0.3 ) Piceance (4.6 ) (2 ) $ (12.0 ) Powder River (2.0 ) (1 ) $ (13.0 ) (6.6 ) (6 ) $ (25.3 ) Revisions: Piceance — — $ (0.1 ) Added in 2015: Williston — — $ — Piceance — — $ — Powder River — — $ — — — $ — Total Proved Undeveloped 0.1 6 $ 0.4 • 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): 2015 2014 2013 Unproved oil and gas properties $ 47,254 $ 75,329 $ 62,553 Proved oil and gas properties 1,008,466 807,518 725,345 Gross capitalized costs 1,055,720 882,847 787,898 Accumulated depreciation, depletion and amortization and valuation allowances (888,775 ) (612,012 ) (592,505 ) Net capitalized costs $ 166,945 $ 270,835 $ 195,393 Results of Operations Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2015 2014 2013 Revenue $ 43,283 $ 55,114 $ 54,884 Production costs 19,762 22,155 20,140 Depreciation, depletion and amortization and valuation provisions 28,062 23,288 16,717 Impairment of long-lived assets 249,608 — — Total costs 297,432 45,443 36,857 Results of operations from producing activities before tax (254,149 ) 9,671 18,027 Income tax benefit (expense) 93,743 (3,415 ) (6,308 ) Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (160,406 ) $ 6,256 $ 11,719 Unproved Properties Unproved properties not subject to amortization at December 31, 2015 , relate primarily to the four wells drilled in the Mancos formation of the Piceance Basin, for which completions were deferred. Unproved properties not subject to amortization at December 31, 2014 and 2013 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $1.0 million , $1.0 million and $1.1 million of interest during 2015 , 2014 and 2013 , respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and notes the year in which the associated costs were incurred (in thousands): 2015 2014 2013 Prior Total Leasehold acquisition cost $ 4,256 $ 4,475 $ 9,006 $ 1,433 $ 19,170 Exploration cost 37,770 8,159 — — 45,929 Capitalized interest 940 351 736 981 3,008 Total $ 42,966 $ 12,985 $ 9,742 $ 2,414 $ 68,107 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): 2015 2014 2013 Future cash inflows $ 295,173 $ 675,973 $ 602,501 Future production costs (146,552 ) (245,180 ) (213,578 ) Future development costs, including plugging and abandonment (24,833 ) (45,123 ) (40,557 ) Future income tax expense — (29,523 ) (81,566 ) Future net cash flows 123,788 356,147 266,800 10% annual discount for estimated timing of cash flows (44,760 ) (173,125 ) (107,375 ) Standardized measure of discounted future net cash flows $ 79,028 $ 183,022 $ 159,425 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): 2015 2014 2013 Standardized measure - beginning of year $ 183,022 $ 159,425 $ 136,103 Sales and transfers of oil and gas produced, net of production costs (29,948 ) (32,139 ) (35,932 ) Net changes in prices and production costs (127,199 ) (28,544 ) 15,126 Extensions, discoveries and improved recovery, less related costs 15,718 17,582 29,574 Changes in future development costs (7,387 ) 3,195 (12,216 ) Development costs incurred during the period 27,211 2,079 3,554 Revisions of previous quantity estimates (6,941 ) 23,722 12,851 Accretion of discount 18,870 18,437 15,126 Net change in income taxes 5,682 19,265 (3,892 ) Purchases of reserves — — — Sales of reserves — — (869 ) Standardized measure - end of year $ 79,028 $ 183,022 $ 159,425 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.

Discontinued Operations_

Discontinued Operations:	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	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 (Loss) and Consolidated Statements of Cash Flows. 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. An additional $1.1 million in 2013 was expensed relative to the claims assigned to arbitration. 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 (Loss) were as follows (in thousands): For the Years Ended December 31, 2013 Revenue $ — Pre-tax income (loss) from discontinued operations — Pre-tax gain (loss) on sale (1,391 ) Income tax (expense) benefit 507 Income (loss) from discontinued operations, net of tax $ (884 ) 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, 2015
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 2015 and 2014 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2015 Revenue $ 441,987 $ 272,254 $ 272,105 $ 318,259 Operating income (loss) $ 70,500 $ (38,858 ) $ (2,044 ) $ 197 Income (loss) from continuing operations $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Net income (loss) available for common stock $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Income (loss) per share - Basic $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Income (loss) per share - Diluted $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Dividends paid per share $ 0.405 $ 0.405 $ 0.405 $ 0.405 Common stock prices - High $ 53.37 $ 52.96 $ 47.27 $ 47.51 Common stock prices - Low $ 47.88 $ 43.48 $ 36.81 $ 40.00 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2014 Revenue $ 460,169 $ 283,237 $ 272,087 $ 378,077 Operating income (loss) $ 90,432 $ 47,412 $ 55,238 $ 70,786 Income (loss) from continuing operations $ 48,645 $ 20,347 $ 27,363 $ 34,534 Net income (loss) available for common stock $ 48,645 $ 20,347 $ 27,363 $ 34,534 Income (loss) per share - Basic $ 1.10 $ 0.46 $ 0.61 $ 0.78 Income (loss) per share - Diluted $ 1.09 $ 0.46 $ 0.61 $ 0.77 Dividends paid per share $ 0.390 $ 0.390 $ 0.390 $ 0.390 Common stock prices - High $ 59.05 $ 61.41 $ 62.13 $ 57.17 Common stock prices - Low $ 51.09 $ 55.23 $ 47.87 $ 47.11

Subsequent Event_

Subsequent Event:	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Completion of SourceGas Acquisition On February 12, 2016, Black Hills Utility Holdings acquired SourceGas from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion . See Note 2 for additional details. Sale of Non-controlling Interest in Subsidiary On February 12, 2016, Black Hills Electric Generation entered into a definitive agreement to sell a 49.9% , non-controlling interest in Black Hills Colorado IPP for $215 million to AIA Energy North America LLC, an infrastructure investment platform managed by Argo Infrastructure Partners. The sale is expected to close in April of 2016, pending receipt of regulatory approval from FERC. Black Hills Colorado IPP owns and operates a 200 MW, combined cycle natural gas generating facility located in Pueblo, Colorado. Black Hills Colorado IPP will continue to own and operate the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Financing Activities On January 20, 2016, we executed a 10 -year $150 million notional amount forward starting interest rate swap at an all-in rate of 2.09% to hedge the risks of interest rate movement between the hedge date and the expected pricing date for our anticipated long-term debt refinancings. The swap will be accounted for as a cash flow hedge and any gain or loss will initially be recorded in AOCI. The swap has a mandatory early termination date of April 12, 2017. On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95% , 10 -year senior notes due 2026, and $250 million of 2.5% , 3 -year senior notes due 2019. These funds were used as funding for the SourceGas Acquisition. After discounts and underwriter fees, net proceeds from the offering totaled $546 million . The discounts will be amortized over the life of each respective note. See Note 2 for additional details.

Schedule II Consolidated Valuat

Schedule II Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014 AND 2013 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: 2015 $ 1,516 $ — $ 3,860 $ 4,132 $ (7,767 ) $ 1,741 2014 $ 1,237 $ — $ 4,470 $ 4,233 $ (8,424 ) $ 1,516 2013 $ 768 $ — $ 2,780 $ 4,999 $ (7,310 ) $ 1,237

Business Description (Policies)

Business Description (Policies)	12 Months Ended
	Dec. 31, 2015
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 22 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 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 4 for additional information. 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 22 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 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. 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 2015. No ceiling test write-down was recorded in 2014 or 2013. See Note 13 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We 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 21 . 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, 2015 . 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 (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations, other than Oil and Gas. For the Oil and Gas segment, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and depleted pursuant to our use of the full cost method.
Fair Value Measurements	Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, 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 (Loss).
Legal Costs	Legal Costs Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been incurred and the amount can be reasonably estimated. Legal costs related to ongoing litigation are expensed as incurred. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, we record a loss contingency at the minimum amount in the range. If the loss contingency at issue is not both probable and reasonably estimable, we do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable.
Regulatory Accounting	Regulatory Accounting Our 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 asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. At December 31, 2015, we have chosen to early adopt on a prospective basis ASU 2015-17 as discussed below under Recently Issued and Adopted Accounting Standards. As of December 31, 2015, we classify all deferred tax assets and liabilities as non-current. The prior period is presented under the previous guidance for classifying deferred tax assets and deferred tax liabilities as current and non-current. 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 (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets.
Earnings per Share of Common Stock	Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to 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 22 for additional information.
Recently Issued and Adopted Accounting Standards	Recently Issued and Adopted Accounting Standards Balance Sheet Classification of Deferred Taxes, ASU 2015-17 In November 2015, the FASB issued ASU 2015-17 providing guidance on financial statement presentation for deferred tax assets and deferred tax liabilities. All deferred taxes are to be presented as non-current. FASB issued this guidance as part of its initiative to reduce complexity in accounting standards. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those years (i.e., in the first quarter of 2017 for calendar year-end companies). The guidance may be applied either prospectively, for all deferred tax assets and liabilities, or retrospectively by reclassifying the comparative balance sheets. Early adoption is permitted. We have chosen early adoption as of December 31, 2015 , on a prospective basis. At December 31, 2015, the balance sheet reflects a net non-current deferred tax liability of $451 million . The balance sheet presentation as of December 31, 2014 was not adjusted retrospectively and remains as previously reported with a net current deferred tax asset of $48 million and a non-current deferred tax liability of $512 million . Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03 In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact that adoption of ASU 2015-03 will have on our financial position, results of operations or cash flows. Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. The guidance also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. On July 9, 2015, FASB voted to defer the effective date of ASU 2014-09 by one year. The guidance would be effective for annual and interim reporting periods beginning after December 15, 2018 and early adoption is permitted. We are currently assessing the impact that adoption of ASU 2014-09 will have on our financial position, results of operations or cash flows. Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward 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 applied 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 (Tables)

Business Description (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 45,296 $ 39,052 $ (689 ) $ 83,659 Gas Utilities 26,713 29,691 (1,039 ) 55,365 Power Generation 1,187 — — 1,187 Coal Mining 2,760 — — 2,760 Oil and Gas 3,502 — (13 ) 3,489 Corporate 1,026 — — 1,026 Total $ 80,484 $ 68,743 $ (1,741 ) $ 147,486 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
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2015 December 31, 2014 Materials and supplies $ 55,726 $ 49,555 Fuel - Electric Utilities 5,567 6,637 Natural gas in storage held for distribution 25,650 34,999 Total materials, supplies and fuel $ 86,943 $ 91,191
Schedule of Accrued Liabilities	The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of (in thousands): December 31, 2015 December 31, 2014 Accrued employee compensation, benefits and withholdings $ 43,342 $ 45,192 Accrued property taxes 32,393 33,688 Accrued payments related to litigation expenses and settlements 38,750 — Customer deposits and prepayments 53,496 26,141 Accrued interest and contract adjustment payments 25,762 14,913 Other (none of which is individually significant) 38,318 50,181 Total accrued liabilities $ 232,061 $ 170,115
Goodwill	Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Ending balance at December 31, 2013 $ 250,487 $ 94,144 $ 8,765 $ 353,396 Additions — — — — Ending balance at December 31, 2014 $ 250,487 $ 94,144 $ 8,765 $ 353,396 Additions (a) 6,363 — — 6,363 Ending balance at December 31, 2015 $ 256,850 $ 94,144 $ 8,765 $ 359,759
Intangible Assets	Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2015 2014 2013 Intangible assets, net, beginning balance $ 3,176 $ 3,397 $ 3,620 Additions 434 — — Amortization expense (a) (230 ) (221 ) (223 ) Intangible assets, net, ending balance $ 3,380 $ 3,176 $ 3,397 _________________ (a) 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) December 31, 2015 December 31, 2014 Regulatory assets Deferred energy and fuel cost adjustments - current (a)(d) 1 $ 24,751 $ 23,820 Deferred gas cost adjustments (a)(d) 2 15,521 37,471 Gas price derivatives (a) 5 23,583 18,740 AFUDC (b) 45 12,870 12,358 Employee benefit plans (c) 12 83,986 97,126 Environmental (a) subject to approval 1,180 1,314 Asset retirement obligations (a) 44 457 3,287 Bond issue cost (a) 22 3,133 3,276 Renewable energy standard adjustment (a) 5 5,068 9,622 Flow through accounting (c) 35 29,722 25,887 Decommissioning costs (b) 10 18,310 12,484 Other regulatory assets (a) 15 13,903 12,454 $ 232,484 $ 257,839 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 7,814 $ 6,496 Employee benefit plans (c) 12 47,218 53,139 Cost of removal (a) 44 90,045 78,249 Other regulatory liabilities (c) 25 7,964 10,947 $ 153,041 $ 148,831 __________ (a) Recovery of costs, but we are not allowed a rate of return. (b) In addition to recovery of costs, we are allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively. (d) Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.
Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands): December 31, 2015 December 31, 2014 December 31, 2013 Income (loss) from continuing operations $ (32,111 ) $ 130,889 $ 118,307 Weighted average shares - basic 45,288 44,394 44,163 Dilutive effect of: Equity compensation — 204 256 Weighted average shares - diluted 45,288 44,598 44,419 Income (loss) from continuing operations, per share - Diluted $ (0.71 ) $ 2.93 $ 2.66
Antidilutive Securities	The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands): December 31, 2015 December 31, 2014 December 31, 2013 Equity compensation 112 81 22 Equity units 6,440 — — Anti-dilutive shares excluded from computation of earnings (loss) per share 6,552 81 22

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
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 2015 2014 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 $ 1,136,847 43 $ 1,125,845 45 25 65 Electric transmission 301,280 52 284,032 49 40 70 Electric distribution 785,351 48 718,342 44 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 180,840 24 152,982 21 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,670,629 2,547,512 Construction work in progress 98,918 49,700 Total electric plant 2,769,547 2,597,212 Less accumulated depreciation and amortization 540,634 484,406 Electric plant net of accumulated depreciation and amortization $ 2,228,913 $ 2,112,806 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 15 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. 2015 2014 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 30 $ 13 37 30 30 Gas transmission 24,081 62 24,090 54 53 70 Gas distribution 607,224 44 557,405 46 41 56 General 100,765 21 90,085 19 16 22 Total gas plant in service 732,083 671,593 Construction work in progress 9,437 16,072 Total gas plant 741,520 687,665 Less accumulated depreciation and amortization 106,778 92,035 Gas plant net of accumulated depreciation and amortization $ 634,742 $ 595,630 2015 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 $ 156,721 $ 2,182 $ 158,903 $ 51,471 $ 107,432 33 2 40 Coal Mining 154,630 3,649 158,279 97,663 60,616 13 2 59 Oil and Gas 1,132,776 — 1,132,776 925,908 206,868 24 3 25 $ 1,444,127 $ 5,831 $ 1,449,958 $ 1,075,042 $ 374,916 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 — 962,395 646,640 315,755 24 3 25 $ 1,261,793 $ 6,010 $ 1,267,803 $ 784,973 $ 482,830 2015 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 376 $ 15,377 $ 15,753 $ (4,770 ) $ 20,523 10 5 30 ___________ (a) Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP. 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 Black Hills Colorado IPP.

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2015 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 111,532 $ 1,039 $ 56,812 Transmission Tie $ 19,648 $ — $ 5,390 Wygen I $ 108,732 $ 636 $ 35,531 Wygen III $ 137,860 $ 446 $ 16,217 Busch Ranch Wind Project $ 18,899 $ — $ 2,345

Business Segments Information (

Business Segments Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting Information, Additional Information [Abstract]
Segment information included in Consolidated Balance Sheets	Segment information was as follows (in thousands): Total Assets (net of inter-company eliminations) as of December 31, 2015 2014 Utilities: Electric (a) $ 2,859,720 $ 2,748,680 Gas 864,858 906,922 Non-regulated Energy: Power Generation (a) 60,864 76,945 Coal Mining 76,358 74,407 Oil and Gas 208,956 332,343 Corporate (b) 584,745 106,605 Total assets $ 4,655,501 $ 4,245,902 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2015 2014 Utilities: Electric Utilities $ 202,075 $ 193,199 Gas Utilities 69,496 70,528 Non-regulated Energy: Power Generation 2,694 2,379 Coal Mining 5,767 6,676 Oil and Gas 168,925 109,439 Corporate 9,864 9,046 Total capital expenditures and asset acquisitions $ 458,821 $ 391,267 _________________ (a) Includes accruals for property, plant and equipment. Property, Plant and Equipment as of December 31, 2015 2014 Utilities: Electric Utilities (a) $ 2,769,547 $ 2,597,212 Gas Utilities 741,520 687,665 Non-regulated Energy: Power Generation (a) 158,903 156,041 Coal Mining 158,279 149,367 Oil and Gas 1,132,776 962,395 Corporate 15,753 10,720 Total property, plant and equipment $ 4,976,778 $ 4,563,400 _______________ (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 Consolidated Statements of Income	Consolidating Income Statement Year ended December 31, 2015 Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas Corporate Inter-company Eliminations Total Revenue $ 712,387 $ 507,139 $ 7,483 $ 34,313 $ 43,283 $ — $ — $ 1,304,605 Inter-company revenue 11,617 — 83,307 30,753 — 227,708 (353,385 ) — Total revenue 724,004 507,139 90,790 65,066 43,283 227,708 (353,385 ) 1,304,605 Fuel, purchased power and cost of natural gas sold 291,563 277,491 — — — 122 (112,289 ) 456,887 Operations and maintenance 173,810 127,837 32,140 41,630 41,593 225,721 (229,786 ) 412,945 Depreciation, depletion and amortization 84,284 28,971 4,329 9,806 29,287 9,273 (10,580 ) 155,370 Impairment of long-lived assets (a) — — — — 249,608 — — 249,608 Operating income (loss) 174,347 72,840 54,321 13,630 (277,205 ) (7,408 ) (730 ) 29,795 Interest expense (57,712 ) (15,359 ) (4,218 ) (433 ) (2,726 ) (57,839 ) 54,568 (83,719 ) Interest income 4,236 479 1,015 34 217 48,582 (52,942 ) 1,621 Other income (expense), net 1,225 532 71 2,247 (337 ) 70,889 (72,190 ) 2,437 Impairment of equity investments (a) — — — — (4,405 ) — — (4,405 ) Income tax benefit (expense) (42,792 ) (20,685 ) (18,539 ) (3,608 ) 104,498 2,926 360 22,160 Income (loss) from continuing operations $ 79,304 $ 37,807 $ 32,650 $ 11,870 $ (179,958 ) $ 57,150 $ (70,934 ) $ (32,111 ) ________________ (a) Oil and Gas includes ceiling test and equity investment impairments (see Note 13 ). Consolidating Income Statement Year ended December 31, 2014 Electric Utilities Gas Utilities Power Generation 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 24,246 7,690 (7,930 ) 144,745 Operating income (loss) 137,673 77,782 49,892 11,910 (11,791 ) 1,239 (2,837 ) 263,868 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 ) 4,768 24 744 (66,625 ) Income (loss) from continuing operations $ 59,552 $ 41,869 $ 28,516 $ 10,452 $ (8,525 ) $ 61,538 $ (62,513 ) $ 130,889 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 17,877 11,624 (12,876 ) 137,324 Operating income (loss) 133,595 76,772 47,760 5,586 (3,358 ) 6,062 (6,972 ) 259,445 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 ) 2,113 (7,778 ) 218 (63,040 ) Income (loss) from continuing operations $ 52,134 $ 32,707 $ 16,288 $ 6,327 $ (1,751 ) $ 54,471 $ (41,869 ) $ 118,307 ________________ (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.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Due Date December 31, 2015 December 31, 2015 December 31, 2014 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Unamortized discount on Senior unsecured notes due 2023 (1,890 ) (2,164 ) Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Corporate term loan due 2017 (a) April 12, 2017 1.28% 300,000 — Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 — Corporate term loan due 2015 (a) June 19, 2015 1.31% — 275,000 Total Corporate Debt 1,322,110 997,836 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 Unamortized discount on First Mortgage Bonds due 2039 (99 ) (102 ) First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 0.05% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 0.05% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 0.75% 2,855 2,855 Total Electric Utilities Debt 544,756 544,753 Total long-term debt 1,866,866 1,542,589 Less current maturities — 275,000 Long-term debt, net of current maturities $ 1,866,866 $ 1,267,589 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (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): 2016 $ — 2017 $ 300,000 2018 $ — 2019 $ — 2020 $ 200,000 Thereafter $ 1,368,855
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Senior unsecured notes due 2023 $ 3,414 $ 494 $ 653 $ 86 Senior unsecured notes due 2014 — — — 635 Senior unsecured notes due 2020 759 167 167 167 Bridge Term Loan 843 4,213 — — RSNs due 2028 1,567 10 — — First mortgage bonds due 2044 (Black Hills Power) (a) 687 24 6 — First mortgage bonds due 2044 (Cheyenne Light) (a) 635 22 6 — First mortgage bonds due 2032 551 33 33 33 First mortgage bonds due 2039 1,809 76 76 76 First mortgage bonds due 2037 674 31 31 31 Black Hills Wyoming project financing due 2016 (b) — — — 3,177 Other 440 43 53 57 Total $ 11,379 $ 5,113 $ 1,025 $ 4,262 _____________ (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 Sheet as of Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Revolving Credit Facility $ 1,705 $ 504 $ 616 $ 752

Notes Payable (Tables)

Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2015
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 December 31, 2015 December 31, 2014 Revolving Credit Facility $ 76,800 $ 75,000
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Senior unsecured notes due 2023 $ 3,414 $ 494 $ 653 $ 86 Senior unsecured notes due 2014 — — — 635 Senior unsecured notes due 2020 759 167 167 167 Bridge Term Loan 843 4,213 — — RSNs due 2028 1,567 10 — — First mortgage bonds due 2044 (Black Hills Power) (a) 687 24 6 — First mortgage bonds due 2044 (Cheyenne Light) (a) 635 22 6 — First mortgage bonds due 2032 551 33 33 33 First mortgage bonds due 2039 1,809 76 76 76 First mortgage bonds due 2037 674 31 31 31 Black Hills Wyoming project financing due 2016 (b) — — — 3,177 Other 440 43 53 57 Total $ 11,379 $ 5,113 $ 1,025 $ 4,262 _____________ (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 Sheet as of Amortization Expense for the years ended December 31, December 31, 2015 2015 2014 2013 Revolving Credit Facility $ 1,705 $ 504 $ 616 $ 752
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, 2015 Covenant Requirement Recourse leverage ratio 60 % Less than 65 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The following tables present the details of ARO which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2014 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) December 31, 2015 Electric Utilities $ 7,012 $ — $ (2,733 ) $ 183 $ — $ 4,462 Gas Utilities 291 — (168 ) 13 — 136 Coal Mining 19,138 — — 993 (1,498 ) 18,633 Oil and Gas 20,945 828 (1,792 ) 1,371 152 21,504 Total $ 47,386 $ 828 $ (4,693 ) $ 2,560 $ (1,346 ) $ 44,735 December 31, 2013 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a)(b) December 31, 2014 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 _____________________ (a) The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions. (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 (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Schedule of Derivative Instruments	The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2015 December 31, 2015 December 31, 2014 Interest Rate Swaps (a) Interest Rate Swaps (b) Interest Rate Swaps (a) Notional $ 75,000 $ 250,000 $ 75,000 Weighted average fixed interest rate 4.97 % 2.29 % 4.97 % Maximum terms in years 1.0 1.3 2.0 Derivative assets, non-current $ — $ 3,441 $ — Derivative liabilities, current $ 2,835 $ — $ 3,340 Derivative liabilities, non-current $ 156 $ — $ 2,680 ___________________ (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. (b) These swaps are designated as cash flow hedges of anticipated debt refinancings.
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): December 31, 2015 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ 2,888 Interest expense $ 3,647 $ — Commodity derivatives 9,782 Revenue (14,460 ) — Total $ 12,670 $ (10,813 ) $ — December 31, 2014 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ (536 ) Interest expense $ 3,669 $ — Commodity derivatives 14,681 Revenue 1,995 — Total $ 14,145 $ 5,664 $ — December 31, 2013 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) Location of Reclassifications from AOCI into Income Amount of (Gain)/Loss Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps $ 7,935 Interest expense $ 6,989 $ — Commodity derivatives (956 ) Revenue (927 ) — Total $ 6,979 $ 6,062 $ — 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): 2015 2014 2013 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 Interest rate swaps - realized (a) Interest expense — — (12,902 ) $ — $ — $ 17,267 _______________ (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: December 31, 2015 December 31, 2014 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) 198,000 4,392,500 334,500 6,582,500 Maximum terms in months (b) 1 1 1 1 Derivative assets, current $ — $ — $ — $ — Derivative assets, non-current $ — $ — $ — $ — Derivative liabilities, current $ — $ — $ — $ — Derivative liabilities, non-current $ — $ — $ — $ — ________________________ (a) Crude in Bbls, gas in MMBtu’s. (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): December 31, 2015 December 31, 2014 Derivative assets, current $ — $ — Derivative assets, non-current $ — $ — Derivative liabilities, current $ — $ — Derivative liabilities, non-current $ — $ — Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities $ 23,578 $ 18,740
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: December 31, 2015 December 31, 2014 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 20,580,000 60 19,370,000 72 Natural gas options purchased 2,620,000 3 4,020,000 8 Natural gas basis swaps purchased 18,150,000 60 12,005,000 60 __________ (a) Term reflects the maximum forward period hedged.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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 11 . The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2015 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Oil and Gas: Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — 6,309 — (6,309 ) — Options -- Gas — — — — — Basis Swaps -- Gas — 4,335 — (4,335 ) — Commodity derivatives - Utilities — 2,293 — (2,293 ) — Interest rate swaps — 3,441 — — 3,441 Total $ — $ 16,378 $ — $ (12,937 ) $ 3,441 Liabilities: Commodity derivatives - Oil and Gas: Options -- Oil $ — $ — $ — $ — $ — Basis Swaps -- Oil — — — — — Options -- Gas — — — — — Basis Swaps -- Gas — 556 — (556 ) — Commodity derivatives - Utilities — 24,585 — (24,585 ) — Interest rate swaps — 2,991 — — 2,991 Total $ — $ 28,132 $ — $ (25,141 ) $ 2,991 As of 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
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): 2015 2014 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 $ 9,981 $ — $ 10,391 $ — Commodity derivatives Derivative assets - non-current 663 — 4,766 — Interest rate swaps Derivative assets - non-current 3,441 — — — Commodity derivatives Derivative liabilities - current — 465 — 185 Commodity derivatives Derivative liabilities - non-current — 91 — 288 Interest rate swaps Derivative liabilities - current — 2,835 — 3,340 Interest rate swaps Derivative liabilities - non-current — 156 — 2,680 Total derivatives designated as hedges $ 14,085 $ 3,547 $ 15,157 $ 6,493 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ — $ — $ — $ — Commodity derivatives Derivative assets - non-current — — — — Commodity derivatives Derivative liabilities - current — 9,586 — 8,032 Commodity derivatives Derivative liabilities - non-current — 12,706 — 8,882 Interest rate swaps Derivative liabilities - current — — — — Interest rate swaps Derivative liabilities - non-current — — — — Total derivatives not designated as hedges $ — $ 22,292 $ — $ 16,914
Schedule of Derivative Offsetting on Balance Sheet	Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2015 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 $ 6,309 $ (6,309 ) $ — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps 4,335 (4,335 ) — Utilities 2,293 (2,293 ) — Interest Rate Swaps 3,441 — 3,441 Total derivative assets subject to a master netting agreement or similar arrangement 16,378 (12,937 ) 3,441 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps — — — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps — — — Utilities — — — Interest rate swaps — — — Total derivative assets not subject to a master netting agreement or similar arrangement — — — Total derivative assets $ 16,378 $ (12,937 ) $ 3,441 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps $ — $ — $ — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps 556 (556 ) — Utilities 24,585 (24,585 ) — Interest Rate Swaps 2,991 — 2,991 Total derivative liabilities subject to a master netting agreement or similar arrangement 28,132 (25,141 ) 2,991 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Oil and Gas - Crude Basis Swaps — — — Oil and Gas - Crude Options — — — Oil and Gas - Natural Gas Basis Swaps — — — Utilities — — — Interest Rate Swaps — — — Total derivative liabilities not subject to a master netting agreement or similar arrangement — — — Total derivative liabilities $ 28,132 $ (25,141 ) $ 2,991 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2014 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 $ 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 Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as of December 31, 2015 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 — — — Interest Rate Swaps Counterparty G 3,441 — 3,441 $ 3,441 $ — $ 3,441 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 $ — $ (1,672 ) $ (1,672 ) Oil and Gas Counterparty B — — — Utilities Counterparty A — (5,367 ) (5,367 ) Interest Rate Swaps Counterparty F 2,991 — 2,991 $ 2,991 $ (7,039 ) $ (4,048 ) 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 Swap Counterparty F 6,020 — 6,020 $ 6,020 $ (7,485 ) $ (1,465 )

Fair Value of Financial Instr44

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value of financial instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2015 2014 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 456,535 $ 456,535 $ 21,218 $ 21,218 Restricted cash and equivalents (a) $ 1,697 $ 1,697 $ 2,056 $ 2,056 Notes payable (a) $ 76,800 $ 76,800 $ 75,000 $ 75,000 Long-term debt, including current maturities (b) $ 1,866,866 $ 1,992,274 $ 1,542,589 $ 1,734,555 _______________ (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_ Stockholders Equity (Tab

Stock: Stockholders Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Schedule of Company's equity units	Selected information about our equity units is presented below (in thousands except for percentages) : Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 33,118

Stock (Tables)

Stock (Tables)	12 Months Ended
	Dec. 31, 2015
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 (Loss) was as follows for the years ended December 31 (in thousands): 2015 2014 2013 Stock-based compensation expense $ 4,076 $ 9,329 $ 12,595
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): 2015 2014 Shares Issued 66 52 Weighted Average Price $ 44.79 $ 54.99 Unissued Shares Available 408 474
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, 2015 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 134 $ 46.12 Granted — — Forfeited/canceled (5 ) 54.29 Expired — — Exercised — — Balance at end of period 129 $ 45.80 7.0 $ 678 Exercisable at end of period 75 $ 40.29 6.3 $ 658 The table below provides details of our option plans at December 31 (in thousands): 2015 2014 2013 Summary of Stock Options Unrecognized compensation expense $ 425 $ 816 $ 130 Intrinsic value of options exercised (a) $ — $ 199 $ 789 Net cash received from exercise of options $ — $ 237 $ 2,046 Tax benefit realized from exercise of shares (b) $ — $ 70 $ 276 _____________________ (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 and restricted stock units at December 31, 2015 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 233 $ 44.60 Granted 107 50.01 Vested (120 ) 41.39 Forfeited (18 ) 49.00 Balance at end of period 202 $ 48.96 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) 2015 $ 50.01 $ 6,009 2014 $ 54.34 $ 6,114 2013 $ 40.56 $ 5,842
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 January 1, 2013 January 1, 2013 - December 31, 2015 61 0% 200% January 1, 2014 January 1, 2014 - December 31, 2016 44 0% 200% January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2015 (in thousands) (in thousands) Performance Shares balance at beginning of period 84 $ 39.58 84 Granted 22 54.92 22 Forfeited — — — Vested (32 ) 32.26 (32 ) Performance Shares balance at end of period 74 $ 31.21 74 $ 4.55 _____________________ (a) The grant date fair values for the performance shares granted in 2015 , 2014 and 2013 were determined by Monte Carlo simulation using a blended volatility of 21% , 23% and 20% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows: Weighted Average Grant Date Fair Value December 31, 2015 $ 54.92 December 31, 2014 $ 55.18 December 31, 2013 $ 35.85 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, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314 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

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Rent expense $ 7,177 $ 6,932 $ 7,169
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): 2016 $ 2,907 2017 $ 2,491 2018 $ 2,268 2019 $ 1,932 2020 $ 1,238 Thereafter $ 6,199

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Current: Federal $ 2,549 $ (2,319 ) $ (2,003 ) State 1,319 (1,288 ) (173 ) 3,868 (3,607 ) (2,176 ) Deferred: Federal (23,592 ) 64,780 58,288 State (2,323 ) 5,658 7,140 Tax credit amortization (113 ) (206 ) (212 ) (26,028 ) 70,232 65,216 $ (22,160 ) $ 66,625 $ 63,040
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): 2015 2014 Deferred tax assets: Regulatory liabilities $ 43,586 $ 49,243 Employee benefits 26,400 26,714 Federal net operating loss 217,922 213,466 Asset impairment (a) 181,731 93,663 Other deferred tax assets (b) 85,907 76,005 Less: Valuation allowance (4,304 ) (5,017 ) Total deferred tax assets 551,242 454,074 Deferred tax liabilities: Accelerated depreciation, amortization and other plant-related differences (709,068 ) (695,280 ) Regulatory assets (29,092 ) (25,340 ) Mining development and oil exploration (183,956 ) (109,571 ) State deferred tax liability (35,065 ) (36,579 ) Deferred costs (26,121 ) (35,284 ) Other deferred tax liabilities (18,519 ) (15,684 ) Total deferred tax liabilities (1,001,821 ) (917,738 ) Net deferred tax liability $ (450,579 ) $ (463,664 ) _______________ (a) Majority of impairment deferred tax asset is related to oil and gas properties. (b) 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: 2015 2014 2013 Federal statutory rate (35.0 )% 35.0 % 35.0 % State income tax (net of federal tax effect) (1.0 ) 1.1 2.4 Amortization of excess deferred income taxes and investment tax credits (0.2 ) (0.1 ) (0.1 ) Percentage depletion in excess of cost (a) (3.5 ) (1.0 ) (0.9 ) Equity AFUDC (0.3 ) (0.1 ) — Tax credits (0.5 ) (0.1 ) (0.5 ) Accounting for uncertain tax positions adjustment (b) 3.5 (0.1 ) 0.7 Flow-through adjustments (c) (3.8 ) (0.9 ) (0.9 ) Other tax differences — (0.1 ) (0.9 ) (40.8 )% 33.7 % 34.8 % _________________________ (a) The tax benefit has remained relatively the same for each period presented, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015. (b) The tax expense recorded in 2015 included the re-measurement related to research and development credits and deductions, which increased tax expense. The combination of the re-measurement, continued accrual of after-tax interest expense associated with other uncertain tax positions primarily the like-kind exchange transaction, and pre-tax net loss resulted in a greater impact on the effective tax rate in 2015. (c) 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. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015.
Summary of Operating Loss Carryforwards	At December 31, 2015 , 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 $ 624,218 2019 to 2035 State Net Operating Loss Carryforward $ 463,679 2015 to 2035
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, 2013 $ 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 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 $ 31,986
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, 2015 , 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

Comprehensive Income (Loss) (Ta

Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2015
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 (Loss) Amount Reclassified from AOCI December 31, 2015 December 31, 2014 Gains and losses on cash flow hedges: Interest rate swaps Interest expense $ 3,647 $ 3,669 Commodity contracts Revenue (14,460 ) 1,995 (10,813 ) 5,664 Income tax Income tax benefit (expense) 4,271 (2,344 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (6,542 ) $ 3,320 Amortization of defined benefit plans: Prior service cost Utilities - Operations and maintenance $ (106 ) $ (102 ) Non-regulated energy operations and maintenance (132 ) (115 ) Actuarial gain (loss) Utilities - Operations and maintenance 1,816 630 Non-regulated energy operations and maintenance 1,006 364 2,584 777 Income tax Income tax benefit (expense) (884 ) (272 ) Total reclassification adjustments related to defined benefit plans, net of tax $ 1,700 $ 505
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within AOCI 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, 2014 $ (4,930 ) $ 10,023 $ (20,137 ) $ (15,044 ) Other comprehensive income (loss) 4,589 (2,957 ) 4,357 5,989 As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) 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 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Years ended December 31, 2015 2014 2013 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 40,250 $ 52,584 $ 59,811 Increase (decrease) in capitalized assets associated with asset retirement obligations $ (518 ) $ (5,634 ) $ 1,235 Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (77,810 ) $ (69,239 ) $ (108,361 ) Income taxes, net $ (1,202 ) $ (413 ) $ (4,573 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 Equity 26% 27% Real estate 5 5 Fixed income 59 58 Cash 1 2 Hedge funds 9 8 Total 100% 100%
Schedule of Defined Contribution Plans Contributions	Contributions for the years ended December 31 were as follows (in thousands): 2015 2014 Defined Contribution Plan Company Retirement Contribution $ 5,564 $ 4,187 Matching contributions - Defined Contribution Plans $ 9,616 $ 9,254 2015 2014 Defined Benefit Plans Defined Benefit Pension Plans $ 10,200 $ 10,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 3,771 $ 3,163 Supplemental Non-Qualified Defined Benefit Plans $ 1,564 $ 1,553
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): 2015 2014 Balance, beginning of period $ 34,753 $ 38,188 Purchase 491 454 Unrealized gain (loss) 1,644 1,789 Realized gain (loss) 1 322 Settlements — (6,000 ) Balance, end of period $ 36,889 $ 34,753
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) December 31, 2015 Technique Input Average Assets: Common Collective Trust - Real Estate (a) $ 11,143 Market Approach Redemption Restriction N/A Hedge Funds (b) $ 25,746 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 AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Retirement Plans Non-pension Defined Benefit Postretirement Plans 2015 2014 2015 2014 2015 2014 Change in benefit obligation: Projected benefit obligation at beginning of year $ 377,772 321,400 $ 41,211 $ 32,960 $ 49,042 $ 45,778 Service cost 6,093 5,448 1,300 2,543 1,808 1,700 Interest cost 15,522 15,852 1,455 1,447 1,801 1,919 Actuarial (gain) loss (a) (28,229 ) 55,384 (2,072 ) 5,814 (1,206 ) 2,275 Benefits paid (b) (14,583 ) (20,312 ) (1,675 ) (1,553 ) (3,771 ) (3,163 ) Medicare Part D accrued — — — — (178 ) (99 ) Plan participants’ contributions — — — — 581 632 Projected benefit obligation at end of year $ 356,575 $ 377,772 $ 40,219 $ 41,211 $ 48,077 $ 49,042 ____________________ (a) Change from 2014 reflects an increase in the discount rate and a change in the mortality tables used in employee benefit plan estimates. (b) Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
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) 2015 2014 2015 2014 2015 2014 Beginning market value of plan assets $ 299,533 $ 280,362 $ — $ — $ 4,705 $ 4,546 Investment income (loss) (6,528 ) 29,283 — — (9 ) (43 ) Employer contributions 10,200 10,200 — — 3,175 2,733 Retiree contributions — — — — 581 632 Benefits paid (14,583 ) (20,312 ) (b) — — (3,771 ) (3,163 ) Plan administrative expenses — — — — — — Ending market value of plan assets $ 288,622 $ 299,533 $ — $ — $ 4,681 $ 4,705 ____________________ (a) Assets of VEBA. (b) Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
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 2015 2014 2015 2014 2015 2014 Regulatory assets $ 68,915 $ 78,864 $ — $ — $ 6,464 $ 7,137 Current liabilities $ — $ — $ 1,568 $ 1,486 $ 3,543 $ 3,273 Non-current assets $ — $ — $ — $ — $ 23 $ — Non-current liabilities $ 67,953 $ 78,239 $ 38,651 $ 39,725 $ 39,855 $ 41,002 Regulatory liabilities $ — $ — $ — $ — $ 3,209 $ 2,983
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 2015 2014 2015 2014 2015 2014 Accumulated benefit obligation - Black Hills Corporation $ 129,729 $ 135,582 $ 30,207 $ 29,843 $ 13,121 $ 12,809 Accumulated benefit obligation - Black Hills Energy 205,194 213,398 351 386 23,796 25,456 Accumulated benefit obligation - Cheyenne Light — — — — 11,160 10,777 Total Accumulated Benefit Obligation $ 334,923 $ 348,980 $ 30,558 $ 30,229 $ 48,077 $ 49,042
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 2015 2014 2013 2015 2014 2013 2015 2014 2013 Service cost $ 6,093 $ 5,448 $ 6,433 $ 1,380 $ 1,498 $ 1,392 $ 1,808 $ 1,700 $ 1,674 Interest cost 15,522 15,852 15,300 1,455 1,447 1,328 1,801 1,919 1,669 Expected return on assets (19,470 ) (18,065 ) (18,615 ) — — — (131 ) (85 ) (79 ) Amortization of prior service cost 58 62 63 2 2 2 (428 ) (428 ) (500 ) Recognized net actuarial loss (gain) 11,037 4,806 12,250 1,081 498 793 408 160 482 Net periodic expense $ 13,240 $ 8,103 $ 15,431 $ 3,918 $ 3,445 $ 3,515 $ 3,458 $ 3,266 $ 3,246
Schedule of Net Periodic Benefit Cost Not yet Recognized	In accordance with accounting standards for defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2015 2014 2015 2014 2015 2014 Net (gain) loss $ 8,777 $ 10,996 $ 6,339 $ 8,396 $ 1,704 $ 1,904 Prior service cost (gain) 41 51 6 8 (1,087 ) (1,218 ) Total AOCI $ 8,818 $ 11,047 $ 6,345 $ 8,404 $ 617 $ 686
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2016 are as follows (in thousands): Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 4,663 $ 539 $ 221 Prior service cost (credit) 38 1 (278 ) Total net periodic benefit cost expected to be recognized during calendar year 2016 $ 4,701 $ 540 $ (57 )
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: 2015 2014 2013 2015 2014 2013 2015 2014 2013 Discount rate 4.59 % 4.20 % 5.05 % 3.92 % 3.64 % 4.21 % 4.26 % 3.92 % 4.62 % Rate of increase in compensation levels 3.52 % 3.78 % 3.78 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plans Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2015 2014 2013 2015 2014 2013 2015 2014 2013 Discount rate: Black Hills Corporation 4.25 % 5.10 % 4.35 % 3.98 % 4.68 % 3.88 % 3.70 % 4.45 % 3.65 % Black Hills Energy 4.15 % 5.00 % 4.25 % 3.30 % 3.75 % 3.00 % 3.65 % 4.25 % 3.50 % Cheyenne Light N/A N/A N/A N/A N/A N/A 4.40 % 5.15 % 4.40 % Expected long-term rate of return on assets (a) 6.75 % 6.75 % 7.25 % N/A N/A N/A 3.00 % 2.00 % 2.00 % Rate of increase in compensation levels 3.78 % 3.78 % 3.78 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The expected rate of return on plan assets is 6.75% for the calculation of the 2016 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 2015 Healthcare trend rate pre-65 Trend for next year 6.35 % 6.35 % 6.35 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2024 2024 2024 Healthcare trend rate post-65 Trend for next year 5.20 % 5.20 % 5.20 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2023 2023 2023 2014 Healthcare trend rate pre-65 Trend for next year 7.50 % 7.50 % 7.50 % Ultimate trend rate 4.50 % 4.50 % 4.50 % 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 4.50 % 4.50 % 4.50 % Year Ultimate Trend Reached 2024 2024 2024
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, 2015 Accumulated Postretirement Benefit Obligation Impact on 2015 Service and Interest Cost Increase 1% $ 2,471 $ 173 Decrease 1% $ (2,088 ) $ (141 )
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 2016 $ 15,700 $ 1,568 $ 4,270 2017 $ 16,666 $ 1,628 $ 4,337 2018 $ 17,620 $ 1,682 $ 4,331 2019 $ 18,809 $ 1,808 $ 4,309 2020 $ 19,764 $ 1,539 $ 4,292 2021-2025 $ 113,480 $ 10,024 $ 19,552
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 December 31, 2015 Level 1 Level 2 Level 3 Total AXA Equitable General Fixed Income $ — $ 1,072 $ — $ 1,072 Common Collective Trust - Cash and Cash Equivalents — 1,556 — 1,556 Common Collective Trust - Equity — 74,885 — 74,885 Common Collective Trust - Fixed Income — 172,016 — 172,016 Common Collective Trust - Real Estate — 2,204 11,143 13,347 Hedge Funds — — 25,746 25,746 Total investments measured at fair value $ — $ 251,733 $ 36,889 $ 288,622 Defined Benefit Pension Plans December 31, 2014 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
Postretirement Health Coverage [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule of Allocation of Plan Assets	Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2015 Level 1 Level 2 Level 3 Total Registered Investment Company Trust - Money Market Mutual Fund $ — $ 4,681 $ — $ 4,681 Total investments measured at fair value $ — 4,681 $ — $ 4,681 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2014 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

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 PPA with PacifiCorp $ 13,990 $ 13,943 $ 13,026 Transmission services agreement with PacifiCorp $ 1,213 $ 1,227 $ 1,384 PPA with Happy Jack $ 3,155 $ 3,919 $ 3,772 PPA with Silver Sage $ 4,107 $ 4,798 $ 4,809 Busch Ranch Wind Project $ 1,734 $ 1,998 $ 1,856 PPAs with Cargill $ 16,112 $ 9,286 $ 12,291
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): 2016 $ 165,484 2017 $ 133,534 2018 $ 82,703 2019 $ 49,196 2020 $ 48,966 Thereafter $ 130,745

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Schedule of Guarantor Obligations	We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2015 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 69,773 Ongoing Contract performance guarantee (b) 89,718 December, 2016 $ 159,491 _______________________ (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. (b) BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements.

Oil and Gas Reserves (Unaudit54

Oil and Gas Reserves (Unaudited): Oil and Gas Exploration and Production Industries Disclosure (Tables)	12 Months Ended
	Dec. 31, 2015
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): 2015 2014 2013 Acquisition of properties: Proved $ 1,407 $ 4,881 $ 234 Unproved 669 5,056 6,022 Exploration costs 35,434 54,355 12,817 Development costs 128,998 52,262 48,641 Asset retirement obligations incurred 566 68 143 Total costs incurred $ 167,074 $ 116,622 $ 67,857
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, 2015 , 2014 and 2013 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. 2015 2014 2013 Oil Gas NGL Oil Gas NGL Oil Gas (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 4,276 65,440 1,720 3,921 63,190 — 4,116 55,985 Production (a) (371 ) (10,058 ) (102 ) (337 ) (7,156 ) (135 ) (336 ) (6,984 ) Additions - acquisitions (sales) (11 ) (828 ) — (40 ) (61 ) — (30 ) (46 ) Additions - extensions and discoveries 199 24,462 232 733 11,003 182 379 10,456 Revisions to previous estimates (643 ) (5,604 ) (98 ) (1 ) (1,536 ) 1,673 (208 ) 3,779 Balance at end of year 3,450 73,412 1,752 4,276 65,440 1,720 3,921 63,190 Proved developed reserves at end of year included above 3,436 73,390 1,752 3,780 57,427 1,530 3,689 60,224 Proved undeveloped reserves at the end of year included in above 14 22 — 496 8,013 191 232 2,966 NYMEX prices $ 50.28 $ 2.59 $ — (b) $ 94.99 $ 4.35 $ — (b) $ 96.94 $ 3.67 Well-head reserve prices $ 44.72 $ 1.27 $ 18.96 $ 85.80 $ 3.33 $ 34.81 $ 89.79 $ 3.45 ________________________ (a) Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.
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, 2015 were: Proved Reserves (in Bcfe) Gross PUD Locations Future Development Costs (in millions) Existing 2014: Williston 1.1 30 $ 5.4 Piceance 9.0 3 $ 23.5 Powder River 2.0 1 $ 13.0 Year End Total 2014 12.1 34 $ 41.9 Dropped 2015: Williston (1.0 ) (21 ) $ (4.6 ) Piceance (4.4 ) (1 ) $ (11.5 ) (5.4 ) (22 ) $ (16.1 ) Drilled in 2015: Williston — (3 ) $ (0.3 ) Piceance (4.6 ) (2 ) $ (12.0 ) Powder River (2.0 ) (1 ) $ (13.0 ) (6.6 ) (6 ) $ (25.3 ) Revisions: Piceance — — $ (0.1 ) Added in 2015: Williston — — $ — Piceance — — $ — Powder River — — $ — — — $ — Total Proved Undeveloped 0.1 6 $ 0.4
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2015 2014 2013 Unproved oil and gas properties $ 47,254 $ 75,329 $ 62,553 Proved oil and gas properties 1,008,466 807,518 725,345 Gross capitalized costs 1,055,720 882,847 787,898 Accumulated depreciation, depletion and amortization and valuation allowances (888,775 ) (612,012 ) (592,505 ) Net capitalized costs $ 166,945 $ 270,835 $ 195,393
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): 2015 2014 2013 Revenue $ 43,283 $ 55,114 $ 54,884 Production costs 19,762 22,155 20,140 Depreciation, depletion and amortization and valuation provisions 28,062 23,288 16,717 Impairment of long-lived assets 249,608 — — Total costs 297,432 45,443 36,857 Results of operations from producing activities before tax (254,149 ) 9,671 18,027 Income tax benefit (expense) 93,743 (3,415 ) (6,308 ) Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (160,406 ) $ 6,256 $ 11,719
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, 2015 and notes the year in which the associated costs were incurred (in thousands): 2015 2014 2013 Prior Total Leasehold acquisition cost $ 4,256 $ 4,475 $ 9,006 $ 1,433 $ 19,170 Exploration cost 37,770 8,159 — — 45,929 Capitalized interest 940 351 736 981 3,008 Total $ 42,966 $ 12,985 $ 9,742 $ 2,414 $ 68,107
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): 2015 2014 2013 Future cash inflows $ 295,173 $ 675,973 $ 602,501 Future production costs (146,552 ) (245,180 ) (213,578 ) Future development costs, including plugging and abandonment (24,833 ) (45,123 ) (40,557 ) Future income tax expense — (29,523 ) (81,566 ) Future net cash flows 123,788 356,147 266,800 10% annual discount for estimated timing of cash flows (44,760 ) (173,125 ) (107,375 ) Standardized measure of discounted future net cash flows $ 79,028 $ 183,022 $ 159,425
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): 2015 2014 2013 Standardized measure - beginning of year $ 183,022 $ 159,425 $ 136,103 Sales and transfers of oil and gas produced, net of production costs (29,948 ) (32,139 ) (35,932 ) Net changes in prices and production costs (127,199 ) (28,544 ) 15,126 Extensions, discoveries and improved recovery, less related costs 15,718 17,582 29,574 Changes in future development costs (7,387 ) 3,195 (12,216 ) Development costs incurred during the period 27,211 2,079 3,554 Revisions of previous quantity estimates (6,941 ) 23,722 12,851 Accretion of discount 18,870 18,437 15,126 Net change in income taxes 5,682 19,265 (3,892 ) Purchases of reserves — — — Sales of reserves — — (869 ) Standardized measure - end of year $ 79,028 $ 183,022 $ 159,425

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): For the Years Ended December 31, 2013 Revenue $ — Pre-tax income (loss) from discontinued operations — Pre-tax gain (loss) on sale (1,391 ) Income tax (expense) benefit 507 Income (loss) from discontinued operations, net of tax $ (884 )

Quarterly Historical Data (Un56

Quarterly Historical Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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 2015 and 2014 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2015 Revenue $ 441,987 $ 272,254 $ 272,105 $ 318,259 Operating income (loss) $ 70,500 $ (38,858 ) $ (2,044 ) $ 197 Income (loss) from continuing operations $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Net income (loss) available for common stock $ 33,850 $ (41,842 ) $ (9,943 ) $ (14,176 ) Income (loss) per share - Basic $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Income (loss) per share - Diluted $ 0.76 $ (0.94 ) $ (0.22 ) $ (0.30 ) Dividends paid per share $ 0.405 $ 0.405 $ 0.405 $ 0.405 Common stock prices - High $ 53.37 $ 52.96 $ 47.27 $ 47.51 Common stock prices - Low $ 47.88 $ 43.48 $ 36.81 $ 40.00 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2014 Revenue $ 460,169 $ 283,237 $ 272,087 $ 378,077 Operating income (loss) $ 90,432 $ 47,412 $ 55,238 $ 70,786 Income (loss) from continuing operations $ 48,645 $ 20,347 $ 27,363 $ 34,534 Net income (loss) available for common stock $ 48,645 $ 20,347 $ 27,363 $ 34,534 Income (loss) per share - Basic $ 1.10 $ 0.46 $ 0.61 $ 0.78 Income (loss) per share - Diluted $ 1.09 $ 0.46 $ 0.61 $ 0.77 Dividends paid per share $ 0.390 $ 0.390 $ 0.390 $ 0.390 Common stock prices - High $ 59.05 $ 61.41 $ 62.13 $ 57.17 Common stock prices - Low $ 51.09 $ 55.23 $ 47.87 $ 47.11

Business Description And Sign57

Business Description And Significant Accounting Policies: Business Description (Details)	12 Months Ended
	Dec. 31, 2015Business_Group
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Business Groups	2

Business Description And Sign58

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (1,741)	$ (1,516)
Accounts receivable, net	147,486	189,992
Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,026	2,555
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(689)	(722)
Accounts receivable, net	83,659	85,466
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(1,039)	(781)
Accounts receivable, net	55,365	92,159
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,187	1,369
Coal Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,760	3,151
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(13)	(13)
Accounts receivable, net	3,489	5,292
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	80,484	119,488
Billed Revenues [Member] | Corporate, Non-Segment [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,026	2,555
Billed Revenues [Member] | Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	45,296	59,714
Billed Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	26,713	47,394
Billed Revenues [Member] | Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,187	1,369
Billed Revenues [Member] | Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,760	3,151
Billed Revenues [Member] | Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	3,502	5,305
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	68,743	72,020
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	39,052	26,474
Unbilled Revenues [Member] | Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	29,691	45,546
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 Sign59

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 55,726	$ 49,555
Fuel - Electric Utilities	5,567	6,637
Natural gas in storage held for distribution	25,650	34,999
Total materials, supplies and fuel	$ 86,943	$ 91,191

Business Description And Sign60

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Employee-related Liabilities, Current	$ 43,342	$ 45,192
Accrual for Taxes Other than Income Taxes, Current	32,393	33,688
Settlement Liabilities, Current	38,750	0
Customer Advances and Deposits, Current	53,496	26,141
Interest Payable, Current	25,762	14,913
Other Accrued Liabilities, Current	38,318	50,181
Accrued Liabilities	$ 232,061	$ 170,115

Business Description And Sign61

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 353,396		$ 353,396
Additions	6,363		0
Goodwill, Ending Balance	359,759		353,396
Electric Utilities [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	250,487		250,487
Additions	6,363	[1]	0
Goodwill, Ending Balance	256,850		250,487
Gas Utilities [Member]
Goodwill [Roll Forward]
Additions	0		0
Power Generation [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765		8,765
Additions	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		94,144
Goodwill, Ending Balance	$ 94,144		$ 94,144
[1]	Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc.

Business Description And Sign62

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Finite-Lived Intangible Assets, Useful Life, Maximum (years)	25 years
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 3,176		$ 3,397	$ 3,620
Intangible assets, additions	434		0	0
Intangible assets, amortization expense	(230)	[1]	(221)	(223)
Intangible assets, net, ending balance	3,380		$ 3,176	$ 3,397
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	200
Future Amortization Expense, Year Two	200
Future Amortization Expense, Year Three	200
Future Amortization Expense, Year Four	200
Future Amortization Expense, Year Five	$ 200
[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 Sign63

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets		$ 232,484	$ 257,839
Regulatory liabilities		$ 153,041	148,831
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	[1]	$ 7,814	6,496
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		12 years
Regulatory liabilities	[2]	$ 47,218	53,139
Cost of removal [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		44 years
Regulatory liabilities	[1]	$ 90,045	78,249
Other regulatory liabilities [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		25 years
Regulatory liabilities	[2]	$ 7,964	10,947
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	[1],[3]	$ 24,751	23,820
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	[1],[3]	$ 15,521	37,471
Gas price derivative [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		5 years
Regulatory assets	[1]	$ 23,583	18,740
Allowance For Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		45 years
Regulatory assets	[4]	$ 12,870	12,358
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		12 years
Regulatory assets	[2]	$ 83,986	97,126
Environmental [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	[1]	$ 1,180	1,314
Asset retirement obligations [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		44 years
Regulatory assets	[1]	$ 457	3,287
Bond issuance cost [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		22 years
Regulatory assets	[1]	$ 3,133	3,276
Renewable energy standard adjustment [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		5 years
Regulatory assets	[1]	$ 5,068	9,622
Flow through accounting [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		35 years
Regulatory assets	[2]	$ 29,722	25,887
Decommissioning costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		10 years
Regulatory assets	[4]	$ 18,310	12,484
Other regulatory assets [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		15 years
Regulatory assets	[1]	$ 13,903	$ 12,454
[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. 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.

Business Description And Sign64

Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Income (loss) from continuing operations	$ (14,176)	$ (9,943)	$ (41,842)	$ 33,850	$ 34,534	$ 27,363	$ 20,347	$ 48,645	$ (32,111)	$ 130,889	$ 118,307
Weighted average shares - Basic									45,288,000	44,394,000	44,163,000
Dilutive effect of:
Equity compensation									0	204,000	256,000
Weighted average shares - diluted									45,288,000	44,598,000	44,419,000
Income (loss) from continuing operations - Diluted (usd per share)									$ (0.71)	$ 2.93	$ 2.66
Securities Excluded From Diluted Earnings Per Share Due To Net Loss									83,000

Business Description And Sign65

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	6,552	81	22
Equity Compensation [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	112	81	22
Equity Unit Purchase Agreements [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	6,440	0	0

Business Description And Sign66

Business Description And Significant Accounting Policies: Discontinued Operations (Details)	12 Months Ended
	Dec. 31, 2013
Energy Marketing [Member]
Disposal Date	Feb. 29, 2012

Business Description And Sign67

Business Description And Significant Accounting Policies: Balance Sheet Classification of Deferred Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Deferred income tax assets, net, current	$ 0	$ 48,288
Deferred income tax liabilities, net, non-current	$ 450,579	$ 511,952

Acquisition (Details)

Acquisition (Details) $ in Thousands	Feb. 12, 2016USD ($)utilitycustomermi	Jan. 13, 2016USD ($)	Nov. 23, 2015USD ($)shares	Dec. 31, 2015USD ($)shares		Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jul. 12, 2015USD ($)
Business Acquisition [Line Items]
Long-term debt - issuance				$ 300,000		$ 160,000	$ 800,000
Issuance of common stock				254,581
Equity units - issuance			$ 290,030	290,030		0	$ 0
Subsequent Event [Member]
Business Acquisition [Line Items]
Long-term debt - issuance		$ 546,000
Black Hills Corporation [Member]
Business Acquisition [Line Items]
Long-term Debt				1,322,110		997,836
Black Hills Corporation [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Long-term Debt		550,000
Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Long-term Debt		$ 300,000
Long-term Debt, Fixed Interest Rate		3.95%
Debt instrument term		10 years
Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Long-term Debt		$ 250,000
Long-term Debt, Fixed Interest Rate		2.50%
Debt instrument term		3 years
Remarketable Junior Subordinated Notes Due 2028 [Member]
Business Acquisition [Line Items]
Debt Instrument, Convertible, Number of Equity Instruments | shares			5,980,000
Remarketable Junior Subordinated Notes Due 2028 [Member] | Black Hills Corporation [Member]
Business Acquisition [Line Items]
Long-term Debt			$ 299,000	$ 299,000	[1]	$ 0
Long-term Debt, Fixed Interest Rate			3.50%	3.50%	[1]
Common Stock [Member]
Business Acquisition [Line Items]
Issuance of common stock, shares | shares			6,325,000	6,325,000
Issuance of common stock			$ 246,000	$ 6,325
Source Gas [Member]
Business Acquisition [Line Items]
Bridge Loan								$ 1,170,000
Source Gas [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Business Combination, Purchase Price	$ 1,890,000
Business Combination, Capital Expenditures	200,000
Business Combination, Debt Assumed	$ 760,000
Bridge Loan		$ 88,000
Number of natural gas utilities acquired | utility	4
Number of customers served with acquisition | customer	429,000
Length of natural gas pipeline (miles) | mi	512
[1]	See Note 12 for RSN details.

Property, Plant and Equipment69

Property, Plant and Equipment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 4,976,778	$ 4,563,400
Less: accumulated depreciation, depletion and amortization		1,717,684	1,357,929
Total property, plant and equipment, net		3,259,094	3,205,471
Corporate, Non-Segment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		376	5,524
Construction in progress, gross		15,377	5,196
Property, plant and equipment, gross		15,753	10,720
Total property, plant and equipment, net		$ 20,523	$ 14,205
Corporate, Non-Segment [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		10 years	11 years
Corporate, Non-Segment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		5 years	5 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	[1]	$ (4,770)	$ (3,485)
Non Regulated Energy Group [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,444,127	1,261,793
Construction in progress, gross		5,831	6,010
Property, plant and equipment, gross		1,449,958	1,267,803
Less: accumulated depreciation, depletion and amortization		1,075,042	784,973
Total property, plant and equipment, net		374,916	482,830
Electric Utilities [Member]
Property, Plant and Equipment [Line Items]
Production		1,136,847	1,125,845
Transmission		301,280	284,032
Distribution		785,351	718,342
Plant acquisition adjustment	[2]	4,870	4,870
General		180,840	152,982
Capital lease - plant in service	[3]	261,441	261,441
Total plant in service before construction work in progress		2,670,629	2,547,512
Construction work in progress		98,918	49,700
Property, plant and equipment, gross	[4]	2,769,547	2,597,212
Less: accumulated depreciation, depletion and amortization		540,634	484,406
Total property, plant and equipment, net		$ 2,228,913	$ 2,112,806
Depreciation, depletion and amortization, remaining amortization period		15 years
Electric Utilities [Member] | Weighted Average [Member] | Production, Electric [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		43 years	45 years
Electric Utilities [Member] | Weighted Average [Member] | Electric transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		52 years	49 years
Electric Utilities [Member] | Weighted Average [Member] | Electric distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		48 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		24 years	21 years
Electric Utilities [Member] | Weighted Average [Member] | Capital lease - plant in service [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] | Capital lease - plant in service [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		70 years
Electric Utilities [Member] | Maximum [Member] | Electric distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		75 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		65 years
Electric Utilities [Member] | Maximum [Member] | Capital lease - plant in service [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		24,081	24,090
Distribution		607,224	557,405
General		100,765	90,085
Total plant in service before construction work in progress		732,083	671,593
Construction work in progress		9,437	16,072
Property, plant and equipment, gross		741,520	687,665
Less: accumulated depreciation, depletion and amortization		106,778	92,035
Total property, plant and equipment, net		$ 634,742	$ 595,630
Gas Utilities [Member] | Weighted Average [Member] | General [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		21 years	19 years
Gas Utilities [Member] | Weighted Average [Member] | Production, Gas [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		30 years	37 years
Gas Utilities [Member] | Weighted Average [Member] | Gas transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		62 years	54 years
Gas Utilities [Member] | Weighted Average [Member] | Gas distribution [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		44 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		30 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		30 years
Gas Utilities [Member] | Maximum [Member] | Gas transmission [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		70 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		$ 156,721	$ 153,779
Construction in progress, gross		2,182	2,262
Property, plant and equipment, gross	[4]	158,903	156,041
Less: accumulated depreciation, depletion and amortization		51,471	47,704
Total property, plant and equipment, net		$ 107,432	$ 108,337
Power Generation [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		33 years	33 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		$ 154,630	$ 145,619
Construction in progress, gross		3,649	3,748
Property, plant and equipment, gross		158,279	149,367
Less: accumulated depreciation, depletion and amortization		97,663	90,629
Total property, plant and equipment, net		$ 60,616	$ 58,738
Coal Mining [Member] | Weighted Average [Member]
Property, Plant and Equipment [Line Items]
Weighted average useful life		13 years	15 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		$ 1,132,776	$ 962,395
Construction in progress, gross		0	0
Property, plant and equipment, gross		1,132,776	962,395
Less: accumulated depreciation, depletion and amortization		925,908	646,640
Total property, plant and equipment, net		$ 206,868	$ 315,755
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
[1]	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.
[2]	The plant acquisition adjustment is included in rate base and is being recovered with 15 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) $ in Thousands	Dec. 31, 2015USD ($)
Electric Utilities [Member] | Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	20.00%
Ownership Amount of Plant in Service	$ 111,532
Ownership Amount of Construction Work in Progress	1,039
Ownership Amount of Plant Accumulated Depreciation	$ 56,812
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	$ 5,390
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	$ 137,860
Ownership Amount of Construction Work in Progress	446
Ownership Amount of Plant Accumulated Depreciation	$ 16,217
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	$ 18,899
Ownership Amount of Construction Work in Progress	0
Ownership Amount of Plant Accumulated Depreciation	$ 2,345
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	$ 108,732
Ownership Amount of Construction Work in Progress	636
Ownership Amount of Plant Accumulated Depreciation	$ 35,531

Business Segments Information_

Business Segments Information: Segment Assets (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Segment Reporting, Asset Reconciling Item
Total Assets		$ 4,655,501	$ 4,245,902
Corporate, Non-Segment [Member]
Segment Reporting, Asset Reconciling Item
Total Assets		584,745	106,605
Electric Utilities [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	[1]	2,859,720	2,748,680
Gas Utilities [Member]
Segment Reporting, Asset Reconciling Item
Total Assets		864,858	906,922
Power Generation [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	[1]	60,864	76,945
Coal Mining [Member]
Segment Reporting, Asset Reconciling Item
Total Assets		76,358	74,407
Oil and Gas [Member]
Segment Reporting, Asset Reconciling Item
Total Assets		$ 208,956	$ 332,343
[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 Information72

Business Segments Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	$ 458,821	$ 391,267
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	9,864	9,046
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	202,075	193,199
Gas Utilities [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	69,496	70,528
Power Generation [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	2,694	2,379
Coal Mining [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	5,767	6,676
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	[1]	$ 168,925	$ 109,439
[1]	Includes accruals for property, plant and equipment.

Business Segments Information73

Business Segments Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Property, plant and equipment, gross		$ 4,976,778	$ 4,563,400
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross		15,753	10,720
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	[1]	2,769,547	2,597,212
Gas Utilities [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross		741,520	687,665
Power Generation [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	[1]	158,903	156,041
Coal Mining [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross		158,279	149,367
Oil and Gas [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross		$ 1,132,776	$ 962,395
[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 Information74

Business Segments Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information
Revenue		$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 378,077	$ 272,087	$ 283,237	$ 460,169	$ 1,304,605		$ 1,393,570	$ 1,275,852
Fuel, purchased power and cost of natural gas sold										456,887		581,782	492,147
Operations and maintenance										412,945		403,175	386,936
Depreciation, depletion and amortization										155,370		144,745	137,324
Impairment of long-lived assets										249,608	[1]	0	0
Operating income		$ 197	$ (2,044)	$ (38,858)	$ 70,500	$ 70,786	$ 55,238	$ 47,412	$ 90,432	29,795		263,868	259,445
Interest expense										(83,719)		(70,960)	(111,788)	[2]
Unrealized gain (loss) on interest rate swaps, net										0		0	30,169
Interest income										1,621		1,925	1,723
Other income (expense), net										2,437		2,681	1,798
Impairment of equity investments										(4,405)	[1]	0	0
Income tax benefit (expense)										22,160		(66,625)	(63,040)
Income (loss) from continuing operations										(32,111)		130,889	118,307
Electric Utilities [Member]
Segment Reporting Information
Revenue										712,387		683,201	651,445
Fuel, purchased power and cost of natural gas sold										291,563		314,573	294,048
Operations and maintenance										173,810		165,641	159,961
Depreciation, depletion and amortization										84,284		79,424	77,704
Impairment of long-lived assets										0
Operating income										174,347		137,673	133,595
Interest expense										(57,712)		(53,402)	(61,537)
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										4,236		4,615	5,277
Other income (expense), net										1,225		1,164	633
Impairment of equity investments										0
Income tax benefit (expense)										(42,792)		(30,498)	(25,834)
Income (loss) from continuing operations										79,304		59,552	52,134
Gas Utilities [Member]
Segment Reporting Information
Revenue										507,139		617,768	539,689
Fuel, purchased power and cost of natural gas sold										277,491		380,852	310,463
Operations and maintenance										127,837		132,635	126,073
Depreciation, depletion and amortization										28,971		26,499	26,381
Impairment of long-lived assets										0
Operating income										72,840		77,782	76,772
Interest expense										(15,359)		(15,725)	(25,234)
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										479		441	976
Other income (expense), net										532		34	(60)
Impairment of equity investments										0
Income tax benefit (expense)										(20,685)		(20,663)	(19,747)
Income (loss) from continuing operations										37,807		41,869	32,707
Power Generation [Member]
Segment Reporting Information
Revenue										7,483		6,401	4,648
Fuel, purchased power and cost of natural gas sold										0		0	0
Operations and maintenance										32,140		33,126	30,186
Depreciation, depletion and amortization										4,329		4,540	5,091
Impairment of long-lived assets										0
Operating income										54,321		49,892	47,760
Interest expense										(4,218)		(4,351)	(21,178)	[2]
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										1,015		682	785
Other income (expense), net										71		(6)	1
Impairment of equity investments										0
Income tax benefit (expense)										(18,539)		(17,701)	(11,080)
Income (loss) from continuing operations										32,650		28,516	16,288
Coal Mining [Member]
Segment Reporting Information
Revenue										34,313		31,086	25,186
Fuel, purchased power and cost of natural gas sold										0		0	0
Operations and maintenance										41,630		41,172	39,519
Depreciation, depletion and amortization										9,806		10,276	11,523
Impairment of long-lived assets										0
Operating income										13,630		11,910	5,586
Interest expense										(433)		(493)	(641)
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										34		59	10
Other income (expense), net										2,247		2,275	2,304
Impairment of equity investments										0
Income tax benefit (expense)										(3,608)		(3,299)	(932)
Income (loss) from continuing operations										11,870		10,452	6,327
Oil and Gas [Member]
Segment Reporting Information
Revenue										43,283		55,114	54,884
Fuel, purchased power and cost of natural gas sold										0		0	0
Operations and maintenance										41,593		42,659	40,365
Depreciation, depletion and amortization										29,287		24,246	17,877
Impairment of long-lived assets	[1]									249,608
Operating income										(277,205)		(11,791)	(3,358)
Interest expense										(2,726)		(2,603)	(2,253)
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										217		918	1,639
Other income (expense), net										(337)		183	108
Impairment of equity investments	[1]									(4,405)
Income tax benefit (expense)										104,498		4,768	2,113
Income (loss) from continuing operations										(179,958)		(8,525)	(1,751)
Intercompany Eliminations [Member]
Segment Reporting Information
Revenue										(353,385)		(349,999)	(344,314)
Fuel, purchased power and cost of natural gas sold										(112,289)		(113,759)	(112,489)
Operations and maintenance										(229,786)		(225,473)	(211,977)
Depreciation, depletion and amortization										(10,580)		(7,930)	(12,876)
Impairment of long-lived assets										0
Operating income										(730)		(2,837)	(6,972)
Interest expense										54,568		55,913	84,250
Unrealized gain (loss) on interest rate swaps, net													0
Interest income										(52,942)		(53,759)	(76,724)
Other income (expense), net										(72,190)		(62,574)	(42,641)
Impairment of equity investments										0
Income tax benefit (expense)										360		744	218
Income (loss) from continuing operations										(70,934)		(62,513)	(41,869)
Intercompany Eliminations [Member] | Electric Utilities [Member]
Segment Reporting Information
Revenue										11,617		14,110	13,863
Intercompany Eliminations [Member] | Gas Utilities [Member]
Segment Reporting Information
Revenue										0		0	0
Intercompany Eliminations [Member] | Power Generation [Member]
Segment Reporting Information
Revenue										83,307		81,157	78,389
Intercompany Eliminations [Member] | Coal Mining [Member]
Segment Reporting Information
Revenue										30,753		32,272	31,442
Intercompany Eliminations [Member] | Oil and Gas [Member]
Segment Reporting Information
Revenue										0		0	0
Operating Segments [Member] | Electric Utilities [Member]
Segment Reporting Information
Revenue										724,004		697,311	665,308
Operating Segments [Member] | Gas Utilities [Member]
Segment Reporting Information
Revenue										507,139		617,768	539,689
Operating Segments [Member] | Power Generation [Member]
Segment Reporting Information
Revenue										90,790		87,558	83,037
Operating Segments [Member] | Coal Mining [Member]
Segment Reporting Information
Revenue										65,066		63,358	56,628
Operating Segments [Member] | Oil and Gas [Member]
Segment Reporting Information
Revenue										43,283		55,114	54,884
Corporate, Non-Segment [Member]
Segment Reporting Information
Revenue										227,708		222,460	220,620
Fuel, purchased power and cost of natural gas sold										122		116	125
Operations and maintenance										225,721		213,415	202,809
Depreciation, depletion and amortization										9,273		7,690	11,624
Impairment of long-lived assets										0
Operating income										(7,408)		1,239	6,062
Interest expense										(57,839)		(50,299)	(85,195)	[2]
Unrealized gain (loss) on interest rate swaps, net													30,169
Interest income										48,582		48,969	69,760
Other income (expense), net										70,889		61,605	41,453
Impairment of equity investments										0
Income tax benefit (expense)										2,926		24	(7,778)
Income (loss) from continuing operations										57,150		61,538	54,471
Consolidation, Eliminations [Member]
Segment Reporting Information
Revenue										$ 0		$ 0	$ 0
[1]	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).
[2]	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.

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Nov. 23, 2015	Dec. 31, 2014	Oct. 01, 2014
Debt Instrument [Line Items]
Long-term Debt, including current maturities		$ 1,866,866			$ 1,542,589
Long-term Debt, Current Maturities		0			(275,000)
Long-term debt, net of current maturities		1,866,866			1,267,589
Electric Utilities [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 544,756			544,753
Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt						$ 160,000
Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Aug. 15, 2032
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		Nov. 1, 2039
Long-term Debt, Fixed Interest Rate		6.13%
Long-term Debt		$ 180,000			180,000
Debt Instrument, Unamortized Discount		$ (99)			(102)
Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Nov. 20, 2037
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		Sep. 1, 2021
Long-term Debt, Variable Interest Rate	[1]	0.05%
Long-term Debt	[1]	$ 7,000			7,000
Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Mar. 1, 2027
Long-term Debt, Variable Interest Rate	[1]	0.05%
Long-term Debt	[1]	$ 10,000			10,000
Electric Utilities [Member] | Series 94 A Debt, Due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Jun. 1, 2024
Long-term Debt, Variable Interest Rate	[1]	0.75%
Long-term Debt	[1]	$ 2,855			2,855
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,322,110			997,836
Black Hills Corporation [Member] | Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Nov. 30, 2023
Long-term Debt, Fixed Interest Rate		4.25%
Long-term Debt		$ 525,000			525,000
Debt Instrument, Unamortized Discount		$ (1,890)			(2,164)
Black Hills Corporation [Member] | Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Jul. 15, 2020
Long-term Debt, Fixed Interest Rate		5.88%
Long-term Debt		$ 200,000			200,000
Black Hills Corporation [Member] | Remarketable Junior Subordinated Notes Due 2028 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date	[2]	Nov. 1, 2028
Long-term Debt, Fixed Interest Rate		3.50%	[2]	3.50%
Long-term Debt		$ 299,000	[2]	$ 299,000	0
Black Hills Power [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Oct. 20, 2044
Long-term Debt, Fixed Interest Rate		4.43%				4.43%
Long-term Debt		$ 85,000			85,000	$ 85,000
Cheyenne Light [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Oct. 20, 2044
Long-term Debt, Fixed Interest Rate		4.53%				4.53%
Long-term Debt		$ 75,000			75,000	$ 75,000
London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan due June 2015 [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 275,000
London Interbank Offered Rate (LIBOR) [Member] | Black Hills Corporation [Member] | Corporate Term Loan Due April 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Apr. 12, 2017
Long-term Debt, Variable Interest Rate	[3]	1.28%
Long-term Debt		$ 300,000			0
London Interbank Offered Rate (LIBOR) [Member] | Black Hills Corporation [Member] | Corporate Term Loan due June 2015 [Member]
Debt Instrument [Line Items]
Long-term Debt, Maturity Date		Jun. 19, 2015
Long-term Debt, Variable Interest Rate	[3]	1.3125%
Long-term Debt		$ 0			$ 275,000
[1]	Variable interest rate.
[2]	See Note 12 for RSN details.
[3]	Variable interest rate, based on LIBOR plus a spread.

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
2,016	$ 0	$ 275,000
2,017	300,000
2,018	0
2,019	0
2,020	200,000
After 2,020	$ 1,368,855

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - Electric Utilities [Member] - USD ($) $ in Thousands	Oct. 01, 2014	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt		$ 544,756	$ 544,753
First Mortgage Bonds Due 2044 [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 160,000
First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 85,000	$ 85,000	85,000
Long-term Debt, Fixed Interest Rate	4.43%	4.43%
First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 75,000	$ 75,000	$ 75,000
Long-term Debt, Fixed Interest Rate	4.53%	4.53%
Polution Control Revenue Bonds Due 2024 [Member] | Black Hills Power [Member]
Debt Instrument [Line Items]
Long-term Debt, Fixed Interest Rate	5.35%
Extinguishment of Debt, Amount	$ 12,000

Long-Term Debt_ Replacement of

Long-Term Debt: Replacement of Corporate Term Loan (Details) - USD ($) $ in Millions	Apr. 13, 2015	Dec. 31, 2015
Corporate Term Loan due June 2015 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 275
Corporate Term Loan Due April 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Increase (Decrease), Other, Net	$ 25
Corporate Term Loan Due April 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.90%
Corporate Debt Securities [Member] | Corporate Term Loan Due April 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 300
Debt Instrument, Maturity Date		Apr. 12, 2017

Long-Term Debt_ Deferred Financ

Long-Term Debt: Deferred Financing Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$ 11,379
Amortization Expense for Deferred Financing Costs	5,113		$ 1,025	$ 4,262
Senior Unsecured Notes Due 2023 [Member] [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	3,414
Amortization Expense for Deferred Financing Costs	494		653	86
Senior Unsecured Notes Due 2014 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	0
Amortization Expense for Deferred Financing Costs	0		0	635
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	759
Amortization Expense for Deferred Financing Costs	167		167	167
Bridge Term Loan
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	843
Amortization Expense for Deferred Financing Costs	4,213		0	0
Remarketable Junior Subordinated Notes Due 2028 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,567
Amortization Expense for Deferred Financing Costs	10		0	0
First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	687
Amortization Expense for Deferred Financing Costs	24	[1]	6	0
First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	635
Amortization Expense for Deferred Financing Costs	22	[1]	6	0
First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	551
Amortization Expense for Deferred Financing Costs	33		33	33
First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,809
Amortization Expense for Deferred Financing Costs	76		76	76
First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	674
Amortization Expense for Deferred Financing Costs	31		31	31
Project Financing Debt Due 2016 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	0
Amortization Expense for Deferred Financing Costs	0		0	3,177	[2]
Deferred Financing Costs, Other [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	440
Amortization Expense for Deferred Financing Costs	$ 43		$ 53	$ 57
[1]	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.
[2]	This project financing was repaid in 2013 and the deferred financing costs were written off.

Long-Term Debt_ Dividend Restri

Long-Term Debt: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2015USD ($)
Utilities Group [Member]
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 316

Notes Payable (Details)

Notes Payable (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Revolving Credit Facility [Line Items]
Balance Outstanding	$ 76,800	$ 75,000
Deferred Finance Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	11,379
Amortization Expense for Deferred Financing Costs	5,113	1,025	$ 4,262
Revolving Credit Facility [Member]
Revolving Credit Facility [Line Items]
Balance Outstanding	76,800	75,000
Current Borrowing Capacity	$ 500,000
Expiration Date	Jun. 26, 2020
Maximum Borrowing Capacity	$ 750,000
Commitment Fee Percentage	0.175%
Letters of Credit Outstanding	$ 33,000	35,000
Deferred Finance Costs [Abstract]
Deferred Finance Costs, Noncurrent, Gross	4,300
Deferred Finance Costs, Noncurrent, Net	1,705
Amortization Expense for Deferred Financing Costs	$ 504	$ 616	$ 752
Debt Covenants Disclosure [Abstract]
Covenant Requirement - Recourse Leverage Ratio, Actual	60.00%
Covenant Requirement - Recourse Leverage Ratio, Maximum	0.65
Revolving Credit Facility [Member] | Base Rate Borrowings [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	0.125%
Revolving Credit Facility [Member] | Eurodollar Borrowings [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.125%
Revolving Credit Facility [Member] | Letters of Credit [Member]
Revolving Credit Facility [Line Items]
Interest Rate at Period End	1.125%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,		$ 47,386	$ 51,851
Liabilities Incurred		828	413
Liabilities Settled		(4,693)	(1,017)
Accretion Expense		2,560	2,186
Revision of Prior Estimate	[1]	(1,346)	(6,047)	[2]
Balance on December 31,		44,735	47,386
Electric Utilities [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,		7,012	6,922
Liabilities Incurred		0	0
Liabilities Settled		(2,733)	(85)
Accretion Expense		183	175
Revision of Prior Estimate		0	0
Balance on December 31,		4,462	7,012
Gas Utilities [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,		291	274
Liabilities Incurred		0	0
Liabilities Settled		(168)	0
Accretion Expense		13	17
Revision of Prior Estimate		0	0
Balance on December 31,		136	291
Coal Mining [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,		19,138	20,627
Liabilities Incurred		0	345
Liabilities Settled		0	0
Accretion Expense		993	951
Revision of Prior Estimate	[1]	(1,498)	(2,785)
Balance on December 31,		18,633	19,138
Oil and Gas [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance on January 1,		20,945	24,028
Liabilities Incurred		828	68
Liabilities Settled		(1,792)	(932)
Accretion Expense		1,371	1,043
Revision of Prior Estimate		152	(3,262)	[2]
Balance on December 31,		$ 21,504	$ 20,945
[1]	The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.
[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 (Det

Risk Management Activities (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)MMBTUbbl	Dec. 31, 2014USD ($)MMBTUbbl
Derivative [Line Items]
Derivative assets, current		$ 0	$ 0
Derivative assets, non-current		3,441	0
Derivative liabilities, current		2,835	3,340
Derivative liabilities, non-current		156	$ 2,680
Oil and Gas [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months		10,000
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative liabilities, current		0
Derivative liabilities, non-current		$ 0
Maximum Term		1 year 4 months
Notional amount	[1]	$ 250,000
Weighted average fixed interest rate		2.29%
Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net		$ 2,800
Crude Oil [Member] | Swaps and Options [Member] | Oil and Gas [Member]
Derivative [Line Items]
Notional amount - commodities | bbl	[2]	198,000	334,500
MaximumTerm Hedged in Cash Flow Hedge	[3]	1 month	1 month
Derivative assets, current		$ 0	$ 0
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 | MMBTU	[2]	4,392,500	6,582,500
MaximumTerm Hedged in Cash Flow Hedge	[3]	1 month	1 month
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		1,100
Utilities Group [Member] | Natural Gas, Distribution [Member]
Derivative [Line Items]
Derivative assets, current		0	0
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		$ 23,578	$ 18,740
Utilities Group [Member] | Natural Gas, Distribution [Member] | Future [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		20,580,000	19,370,000
Maximum Term	[4]	60 months	72 months
Utilities Group [Member] | Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		2,620,000	4,020,000
Maximum Term	[4]	3 months	8 months
Utilities Group [Member] | Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member]
Derivative [Line Items]
Notional amount - commodities | MMBTU		18,150,000	12,005,000
Maximum Term	[4]	60 months	60 months
Revolving Credit Facility [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, non-current		$ 0	$ 0
Derivative liabilities, current		2,835	3,340
Derivative liabilities, non-current		$ 156	$ 2,680
Maximum Term		1 year	2 years
Notional amount	[5]	$ 75,000	$ 75,000
Weighted average fixed interest rate		4.97%	4.97%
[1]	These swaps are designated as cash flow hedges of anticipated debt refinancings.
[2]	Crude in Bbls, gas in MMBtu’s.
[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.
[5]	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.

Risk Management Activities_ Hed

Risk Management Activities: Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$ 0	$ 0	$ 17,267
Cash Flow Hedging [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	12,670	14,145	6,979
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(10,813)	5,664	6,062
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	2,888	(536)	7,935
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	3,647	3,669	6,989
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	9,782	14,681	(956)
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	(14,460)	1,995	(927)
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	0	30,169	[1]
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	$ 0	$ (12,902)	[1]
[1]	These interest rate swaps were settled in the fourth quarter of 2013.

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	$ 3,441	$ 0
Derivative, Liabilities, Fair Value Disclosure	2,991	6,020
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	(12,937)	(17,546)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(25,141)	(19,776)
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	16,378	17,546
Derivative Liabilities, Total	28,132	25,796
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 Assets, Commodity Derivatives	3,441
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	0
Derivative, Liabilities, Fair Value Disclosure	2,991	6,020
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 Assets, Commodity Derivatives	0
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 Assets, Commodity Derivatives	3,441
Derivative, Liabilities, Fair Value Disclosure	2,991	6,020
Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0
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	(6,309)	(8,599)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	6,309	8,599
Derivative, Liabilities, Fair Value Disclosure	0	0
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	(4,335)	(6,558)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(556)	(473)
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	4,335	6,558
Derivative, Liabilities, Fair Value Disclosure	556	473
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	(2,293)	(2,389)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(24,585)	(19,303)
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	2,293	2,389
Derivative, Liabilities, Fair Value Disclosure	24,585	19,303
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	3,441	0
Derivative Liabilities, Total	2,991	6,020
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	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Estimate of Fair Value Measurement [Member] | Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
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	0
Derivative, Liabilities, Fair Value Disclosure	$ 0	$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 16,378	$ 17,546
Derivative Liability, Fair Value, Gross Liability	28,132	25,796
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	14,085	15,157
Derivative Liability, Fair Value, Net	3,547	6,493
Derivatives Not Designated as Hedge Instruments [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	0	0
Derivative Liability, Fair Value, Net	22,292	16,914
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	9,981	10,391
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	663	4,766
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	465	185
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	91	288
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	0
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	9,586	8,032
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	12,706	8,882
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Assets, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,441	0
Derivative Asset, Fair Value, Gross Liability	0	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	2,835	3,340
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	156	2,680
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_ Bala87

Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 16,378	$ 17,546
Gross Amounts Offset In Statement Of Financial Position Assets	(12,937)	(17,546)
Derivative Asset	3,441	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	28,132	25,796
Gross Amounts Offset In Statement Of Financial Position Liabilities	(25,141)	(19,776)
Derivative Liability	2,991	6,020
Contract Subject to Master Netting Arrangement [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	16,378	17,546
Gross Amounts Offset In Statement Of Financial Position Assets	(12,937)	(17,546)
Derivative Asset	3,441	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	28,132	19,776
Gross Amounts Offset In Statement Of Financial Position Liabilities	(25,141)	(19,776)
Derivative Liability	2,991	0
Contract Subject to Master Netting Arrangement [Member] | Interest Rate Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	3,441
Gross Amounts Offset In Statement Of Financial Position Assets	0
Derivative Asset	3,441
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,991	0
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	2,991	0
Contract Not Subject to Master Netting Arrangement [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	6,020
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	6,020
Contract Not Subject to Master Netting Arrangement [Member] | Interest Rate Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	0
Gross Amounts Offset In Statement Of Financial Position Assets	0
Derivative Asset	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	6,020
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	0	6,020
Crude Oil [Member] | Contract Subject to Master Netting Arrangement [Member] | Basis Swap [Member]
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	6,309	8,599
Gross Amounts Offset In Statement Of Financial Position Assets	(6,309)	(8,599)
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 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	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] | 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	4,335	6,558
Gross Amounts Offset In Statement Of Financial Position Assets	(4,335)	(6,558)
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	556	473
Gross Amounts Offset In Statement Of Financial Position Liabilities	(556)	(473)
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	2,293	2,389
Gross Amounts Offset In Statement Of Financial Position Assets	(2,293)	(2,389)
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	24,585	19,303
Gross Amounts Offset In Statement Of Financial Position Liabilities	(24,585)	(19,303)
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_ Bala88

Fair Value Measurements: Balance Sheet Offsetting by Counterparty (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Derivative Asset	$ 3,441	$ 0
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, after Netting and Cash Collateral Not Offset Within Derivative Assets	3,441	0
Derivative Liability [Abstract]
Derivative Liability	2,991	6,020
Derivative, Collateral, Right to Reclaim Cash	(7,039)	(7,485)
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	(4,048)	(1,465)
Counterparty F [Member]
Derivative Liability [Abstract]
Derivative Liability	2,991	6,020
Derivative, Collateral, Right to Reclaim Cash	0	0
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	2,991	6,020
Counterparty G [Member]
Derivative Asset [Abstract]
Derivative Asset	3,441
Derivative, Collateral, Obligation to Return Cash	0
Derivative Asset, after Netting and Cash Collateral Not Offset Within Derivative Assets	3,441
Utilities Group [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 Within Derivative Assets	0	0
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	(5,367)	(3,093)
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	(5,367)	(3,093)
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 Within Derivative Assets	0	0
Derivative Liability [Abstract]
Derivative Liability	0	0
Derivative, Collateral, Right to Reclaim Cash	(1,672)	(4,392)
Derivative Liability, After Netting and Cash Collateral Not Offset Within Derivative Liabilities	(1,672)	(4,392)
Oil and Gas [Member] | Counterparty B [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 Within Derivative Assets	0	0
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 Instr89

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount		$ 456,535	$ 21,218
Restricted cash - carrying amount		1,697	2,056
Notes payable		76,800	75,000
Long-term debt, including current maturities - carrying amount		1,866,866	1,542,589
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount		456,535	21,218
Restricted cash - carrying amount		1,697	2,056
Notes payable		76,800	75,000
Long-term debt, including current maturities - carrying amount		1,866,866	1,542,589
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - fair value	[1]	456,535	21,218
Restricted Cash - fair value	[1]	1,697	2,056
Notes payable - fair value	[1]	76,800	75,000
Long-term debt, including current maturities - fair value	[2]	$ 1,992,274	$ 1,734,555
[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.

Equity Units (Details)

Equity Units (Details) $ / shares in Units, shares in Thousands	Nov. 23, 2015USD ($)shares$ / shares	Dec. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Debt Instrument [Line Items]
Proceeds from Sale of Interest in Corporate Unit	$ 299,000,000
Equity Unit Stated Amount (usd per share) | $ / shares	$ 50
Corporate Units Ownership Interest Percentage In Subordinated Notes	5.00%
Debt Instrument, Subordinated Notes, Stated Principal Amount	$ 1,000
Debt Instrument, Convertible, Threshold Consecutive Trading Days	20 days
Debt Instrument, Convertible, Reference Price (usd per share) | $ / shares	$ 40.25
Equity units - issuance	$ 290,030,000	$ 290,030,000		$ 0	$ 0
Stock Purchase Contract Rate	4.25%
Equity Unit, Annual Dividend Amount (usd per share) | $ / shares	$ 2.125
Stock Purchase Contract Liability	$ 33,118,000
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.0572
Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.2422
Black Hills Corporation [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,322,110,000		997,836,000
Remarketable Junior Subordinated Notes Due 2028 [Member]
Debt Instrument [Line Items]
Debt Instrument, Convertible, Number of Equity Instruments | shares	5,980
Debt Instrument, Convertible, Conversion Price (usd per share) | $ / shares	$ 47.2938
Remarketable Junior Subordinated Notes Due 2028 [Member] | Black Hills Corporation [Member]
Debt Instrument [Line Items]
RSN Interest Rate	3.50%	3.50%	[1]
Long-term Debt	$ 299,000,000	$ 299,000,000	[1]	$ 0
[1]	See Note 12 for RSN details.

Stock_ Common Stock Offering (D

Stock: Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 23, 2015	Dec. 31, 2015
Class of Stock [Line Items]
Issuance of common stock		$ 254,581
Common Stock [Member]
Class of Stock [Line Items]
Issuance of common stock, shares	6,325,000	6,325,000
Shares issued, price (usd per share)	$ 40.25
Issuance of common stock	$ 246,000	$ 6,325

Stock_ Equity Compensation Plan

Stock: Equity Compensation Plans Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stockholders' Equity Note [Abstract]
Shares available for grant	1,256,747
Unrecognized compensation expense	$ 7,700
Weighted-average recognition period	1 year 8 months
Stock-based compensation expense	$ 4,076	$ 9,329	$ 12,595

Stock_ Stock Option Activity (D

Stock: Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Weighted-average recognition period		1 year 8 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		134
Granted		0
Forfeited/canceled		(5)
Expired		0
Exercised		0
Options, Shares - Ending		129	134
Exercisable at end of period		75
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Options, Outstanding (usd per share) (Beginning)		$ 46.12
Granted (usd per share)		0
Forfeited/canceled (usd per share)		54.29
Expired (usd per share)		0
Exercised (usd per share)		0
Options, Outstanding (usd per share) (Ending)		45.80	$ 46.12
Exercisable at end of period (usd per share)		$ 40.29
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Options, Weighted average remaining contractual term		7 years
Exercisable at end of period, weighted average remaining contractual term		6 years 3 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Options, aggregate intrinsic value		$ 678
Exercisable at end of period, aggregate intrinsic value		658
Unrecognized compensation expense		425	$ 816	$ 130
Intrinsic value of options exercised	[1]	0	199	789
Net cash received from exercise of options		0	237	2,046
Tax benefit realized from exercise of shares	[2]	$ 0	$ 70	$ 276
Weighted-average recognition period		1 year 1 month
[1]	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.
[2]	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

Stock_ Restricted Stock (Detail

Stock: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Unrecognized compensation expense	$ 7,700
Weighted-average recognition period	1 year 8 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	233
Granted	107
Vested	(120)
Forfeited	(18)
Restricted Stock at end of period	202	233
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)	$ 44.60
Granted (usd per share)	50.01	$ 54.34	$ 40.56
Vested (usd per share)	41.39
Forfeited (usd per share)	49
Balance at end of period (usd per share)	$ 48.96	$ 44.60
Restricted Stock and RSUs, total fair value of shares vested	$ 6,009	$ 6,114	$ 5,842
Unrecognized compensation expense	$ 6,000
Weighted-average recognition period	1 year 9 months 9 days

Stock_ Performance Shares (Deta

Stock: Performance Shares (Details) - USD ($) $ / shares in Units, shares in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense		$ 7,700,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Weighted-average recognition period		1 year 8 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		$ 2,200,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period		44	61
Performance Shares, Number of Shares Authorized, End of Period		43	44	61
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Granted (usd per share)		$ 55.18	$ 35.85
Blended volatility		21.00%	23.00%	20.00%
Historical volatility		50.00%
Implied volatility		50.00%
Performance Shares Issued During Period, Shares, Treasury Stock Reissued		69	59	63
Performance Shares, Total Share-based Liabilities Paid		$ 3,657,000	$ 3,011,000	$ 2,267,000
Performance Shares, Vested in Period, Total Intrinsic Value		7,314,000	$ 6,020,000	$ 4,533,000
Target shares, value		0
Unrecognized compensation expense		$ 1,300,000
Weighted-average recognition period		1 year 8 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		84
Performance Shares, Granted in Period		22
Performance Shares, Forfeited in Period		0
Performance Shares, Vested in Period		(32)
Performance Shares, Number of Shares Authorized, End of Period		74	84
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at end of period (usd per share)		$ 4.55
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		84
Performance Shares, Granted in Period		22
Performance Shares, Forfeited in Period		0
Performance Shares, Vested in Period		(32)
Performance Shares, Number of Shares Authorized, End of Period		74	84
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at beginning of period (usd per share)	[1]	$ 39.58
Granted (usd per share)	[1]	54.92
Forfeited (usd per share)	[1]	0
Vested (usd per share)	[1]	32.26
Balance at end of period (usd per share)	[1]	$ 31.21	$ 39.58
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%
[1]	The grant date fair values for the performance shares granted in 2015, 2014 and 2013 were determined by Monte Carlo simulation using a blended volatility of 21%, 23% and 20%, 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] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Percent of recent average market price	100.00%
Shares Issued	66	52
Weighted Average Price (usd per share)	$ 44.79	$ 54.99
Unissued Shares Available	408	474

Stock_ Preferred Stock (Details

Stock: Preferred Stock (Details)	Dec. 31, 2015shares
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Impairment of Assets (Details)

Impairment of Assets (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)$ / bbl$ / MMcf		Dec. 31, 2014USD ($)$ / bbl$ / MMcf	Dec. 31, 2013USD ($)$ / bbl$ / MMcf
Impaired Assets Held and Used [Line Items]
Impairment of long-lived assets | $		$ 249,608	[1]	$ 0	$ 0
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf		2.59		4.35	3.67
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf		1.27		3.33	3.45
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl		50.28		94.99	96.94
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl		44.72		85.80	89.79
Oil and Gas [Member]
Impaired Assets Held and Used [Line Items]
Impairment of long-lived assets | $	[1]	$ 249,608
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf		2.59
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf		1.27
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl		50.28
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl		44.72
[1]	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).

Impairment Of Assets_ Equity In

Impairment Of Assets: Equity Investments In Unconsolidated Subsidiaries (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Equity Method Investment, Other than Temporary Impairment		$ 4,405	[1]	$ 0	$ 0
Oil and Gas [Member]
Equity Method Investment, Other than Temporary Impairment	[1]	$ 4,405
Willow Creek / Lodge Creek Pipeline And Gathering System [Member] | Oil and Gas [Member]
Equity Method Investment, Ownership Percentage		25.00%
Equity Method Investment, Other than Temporary Impairment		$ 5,200
Equity Method Investment, Realized Gain (Loss) on Disposal		$ 800
[1]	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).

Operating Lease (Details)

Operating Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 7,177	$ 6,932	$ 7,169
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,016	2,907
2,017	2,491
2,018	2,268
2,019	1,932
2,020	1,238
Thereafter	$ 6,199

Income Taxes_ Current and Defer

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	$ 2,549	$ (2,319)	$ (2,003)
State	1,319	(1,288)	(173)
Total Current	3,868	(3,607)	(2,176)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	(23,592)	64,780	58,288
State	(2,323)	5,658	7,140
Tax credit amortization	(113)	(206)	(212)
Total Deferred	(26,028)	70,232	65,216
Total	$ (22,160)	$ 66,625	$ 63,040

Income Taxes_ Deferred Income T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities		$ 43,586	$ 49,243
Employee benefits		26,400	26,714
Federal net operating loss		217,922	213,466
Asset impairment	[1]	181,731	93,663
Other deferred tax assets	[2]	85,907	76,005
Less: Valuation allowance		(4,304)	(5,017)
Total deferred tax assets		551,242	454,074
Deferred Tax Liabilities, Net [Abstract]
Accelerated depreciation, amortization and other plant-related differences		(709,068)	(695,280)
Regulatory assets		(29,092)	(25,340)
Mining development and oil exploration		(183,956)	(109,571)
State deferred tax liability		(35,065)	(36,579)
Deferred costs		(26,121)	(35,284)
Other deferred tax liabilities		(18,519)	(15,684)
Total deferred tax liabilities		(1,001,821)	(917,738)
Net deferred tax liability		$ (450,579)	$ (463,664)
[1]	Majority of impairment deferred tax asset is related to oil and gas properties.
[2]	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, 2015		Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal Statutory Rate		(35.00%)		35.00%	35.00%
State Income Tax (net of federal tax effect)		(1.00%)		1.10%	2.40%
Amortization Of Excess Deferred and Investment Tax Credits		(0.20%)		(0.10%)	(0.10%)
Percentage Depletion In Excess of Cost		(3.50%)	[1]	(1.00%)	(0.90%)
Equity AFUDC		(0.30%)		(0.10%)	0.00%
Tax Credits		(0.50%)		(0.10%)	(0.50%)
Accounting for Uncertain Tax Positions Adjustment		3.50%	[2]	(0.10%)	0.70%
Flow Through Adjustments	[3]	(3.80%)		(0.90%)	(0.90%)
Other Tax Differences		0.00%		(0.10%)	(0.90%)
Effective Income Tax Rate, Continuing Operations		(40.80%)		33.70%	34.80%
[1]	The tax benefit has remained relatively the same for each period presented, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015.
[2]	The tax expense recorded in 2015 included the re-measurement related to research and development credits and deductions, which increased tax expense. The combination of the re-measurement, continued accrual of after-tax interest expense associated with other uncertain tax positions primarily the like-kind exchange transaction, and pre-tax net loss resulted in a greater impact on the effective tax rate in 2015.
[3]	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. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015.

Income Taxes_ Net Operating Los

Income Taxes: Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	$ (22,160)	$ 66,625	$ 63,040
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	624,218
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	463,679
State and Local Jurisdiction [Member] | Valuation Allowance, Operating Loss Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	(200)
Operating Loss Carryforwards Valuation Allowance	800
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 200
Minimum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2019
Minimum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2015
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2035
Maximum [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2035

Income Taxes_ Reconciliation of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 32,192	$ 37,631	$ 40,683
Additions for prior year tax positions	3,285	1,253	1,526
Reductions for prior year tax positions	(3,491)	(6,692)	(4,578)
Additions for current year tax positions	0	0	0
Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	31,986	$ 32,192	$ 37,631
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 2,600

Income Taxes_ Interest, Penalti

Income Taxes: Interest, Penalties and Audits (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 24, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense		$ 1,800	$ 1,600	$ 1,600
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		13,300	11,500
Deferred Income Tax Expense (Benefit)		(26,028)	70,232	65,216
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		0	$ 0	$ 0
Like-Kind Exchange, Aquila and IPP Transactions [Member]
Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)		$ 125,000
Subsequent Event [Member]
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	$ 21,000

Income Taxes_ Carryforwards, St

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Tax Credit Carryforward [Line Items]
Income Tax Expense (Benefit)	$ (22,160)	$ 66,625	$ 63,040
Minimum [Member] | Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2015
Maximum [Member] | Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2017
Foreign Tax Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 500
Tax Credit Carryforward, Valuation Allowance	$ 500
Internal Revenue Service (IRS) [Member] | Minimum [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2,007
Internal Revenue Service (IRS) [Member] | Maximum [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2,009
Internal Revenue Service (IRS) [Member] | Settlement with Taxing Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 1,800
State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	3,000
State and Local Jurisdiction [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	14,793
State and Local Jurisdiction [Member] | Research Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	155
State and Local Jurisdiction [Member] | Deferred Tax Asset [Domain]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	500
Income Tax Expense (Benefit)	(300)
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	$ (200)
State and Local Jurisdiction [Member] | Minimum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2023
State and Local Jurisdiction [Member] | Maximum [Member] | Investment Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2025

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									$ 86,278	$ 73,017	$ 113,979
Revenue	$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 378,077	$ 272,087	$ 283,237	$ 460,169	1,304,605	1,393,570	1,275,852
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes									(49,522)	197,515	181,433
Utilities - Operations and maintenance									272,407	270,954	261,919
Non-regulated energy operations and maintenance									88,702	88,141	83,762
Income tax benefit (expense)									22,160	(66,625)	$ (63,040)
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									(10,813)	5,664
Income tax benefit (expense)									4,271	(2,344)
Net income (loss) available for common stock									(6,542)	3,320
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									3,647	3,669
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									(14,460)	1,995
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									(106)	(102)
Non-regulated energy operations and maintenance									(132)	(115)
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									1,816	630
Non-regulated energy operations and maintenance									1,006	364
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									2,584	777
Income tax benefit (expense)									(884)	(272)
Net income (loss) available for common stock									$ 1,700	$ 505

Other Comprehensive Income_ Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (15,044)	$ (17,422)
Other comprehensive income (loss), net of tax	5,989	2,378	$ 18,066
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(9,055)	(15,044)	(17,422)
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	(4,930)	(6,625)
Other comprehensive income (loss), net of tax	4,589	1,695
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(341)	(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	10,023	(508)
Other comprehensive income (loss), net of tax	(2,957)	10,531
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	7,066	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	(20,137)	(10,289)
Other comprehensive income (loss), net of tax	4,357	(9,848)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (15,780)	$ (20,137)	$ (10,289)

Supplemental Cash Flow Infor110

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Non-cash Investing and Financing Activities from Continuing Operations [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 40,250	$ 52,584	$ 59,811
Increase (decrease) in capitalized assets associated with asset retirement obligations	(518)	(5,634)	1,235
Cash (paid) refunded during the period for continuing operations [Abstract]
Interest (net of amounts capitalized)	(77,810)	(69,239)	(108,361)
Income taxes, net	$ (1,202)	$ (413)	$ (4,573)

Employee Benefit Plans_ Narrati

Employee Benefit Plans: Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
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	December 31
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%
Pension Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (68)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	6.75%	[1]	6.75%	7.25%
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (40)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (43)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	3.00%		2.00%	2.00%
Maximum [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Employers Matching Contribution, Annual Vesting Percentage	100.00%
[1]	The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

Employee Benefit Plans_ Target

Employee Benefit Plans: Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	26.00%	27.00%
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%	5.00%
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	59.00%	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	1.00%	2.00%
Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	9.00%	8.00%

Employee Benefit Plans_ Plan Co

Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 10,000
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	10,200	$ 10,200
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	3,771	3,163
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	1,564	1,553
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	5,564	4,187
Defined Contribution Plan, 401K [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 9,616	$ 9,254

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
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		$ 288,622		$ 299,533	$ 280,362
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		251,733		264,780
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		36,889		34,753
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		1,072		541
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		1,072		541
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		1,556		4,013
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		1,556		4,013
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		74,885		81,636
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		74,885		81,636
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		172,016		174,726
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		172,016		174,726
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		13,347		13,583
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		2,204		3,864
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		11,143	[1]	9,719
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		25,746		25,034
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		25,746	[2]	25,034
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	[3]	4,681		4,705	$ 4,546
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		4,681		4,705
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		4,681		4,705
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		4,681		4,705
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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	$ 288,622		$ 299,533	$ 280,362
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	34,753		38,188
Purchase	491		454
Unrealized gain (loss)	1,644		1,789
Realized gain (loss)	1		322
Settlements	0		(6,000)
Balance, end of period	36,889		34,753
Defined Benefit Plan, Fair Value of Plan Assets	36,889		34,753
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	13,347		13,583
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	11,143	[1]	9,719
Hedge Funds
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	25,746		25,034
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	$ 25,746	[2]	$ 25,034
[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_ Chan116

Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year		$ 377,772		$ 321,400
Service Cost		6,093		5,448		$ 6,433
Interest Cost		15,522		15,852		15,300
Actuarial (Gain) Loss		(28,229)	[1]	55,384
Benefits Paid		(14,583)		(20,312)	[2],[3]
Defined Benefit Plan, Benefit Obligation		377,772		321,400		321,400
Medicare Part D Accrued		0		0
Plan Participants' Contributions		0		0
Projected Benefit Obligation at End of Year		356,575		377,772		321,400
Defined Benefit Plan, One Time Lump Sum Benefit Paid				6,100
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year		41,211		32,960
Service Cost		1,300		2,543
Interest Cost		1,455		1,447
Actuarial (Gain) Loss		(2,072)	[1]	5,814
Benefits Paid		0		0
Defined Benefit Plan, Benefit Obligation		41,211		32,960		32,960
Benefits Paid		(1,675)		(1,553)
Medicare Part D Accrued		0		0
Plan Participants' Contributions		0		0
Projected Benefit Obligation at End of Year		40,219		41,211		32,960
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year		49,042		45,778
Service Cost		1,808		1,700		1,674
Interest Cost		1,801		1,919		1,669
Actuarial (Gain) Loss		(1,206)	[1]	2,275
Benefits Paid	[4]	(3,771)		(3,163)
Defined Benefit Plan, Benefit Obligation		49,042		45,778		45,778
Benefits Paid		(3,771)		(3,163)
Medicare Part D Accrued		(178)		(99)
Plan Participants' Contributions		581		632
Projected Benefit Obligation at End of Year		$ 48,077		$ 49,042		$ 45,778
[1]	Change from 2014 reflects an increase in the discount rate and a change in the mortality tables used in employee benefit plan estimates.
[2]	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
[3]	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
[4]	Assets of VEBA.

Employee Benefit Plans_ Chan117

Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning market value of plan assets		$ 299,533	$ 280,362
Investment income (loss)		(6,528)	29,283
Pension and Other Postretirement Benefit Contributions		10,200	10,200
Retiree contributions		0	0
Benefits paid		(14,583)	(20,312)	[1],[2]
Plan administrative expenses		0	0
Ending market value of plan assets		288,622	299,533
Lump Sum Payment			6,100
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
Pension and Other Postretirement Benefit 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	[3]	4,705	4,546
Investment income (loss)	[3]	(9)	(43)
Pension and Other Postretirement Benefit Contributions	[3]	3,175	2,733
Retiree contributions	[3]	581	632
Benefits paid	[3]	(3,771)	(3,163)
Plan administrative expenses	[3]	0	0
Ending market value of plan assets	[3]	$ 4,681	$ 4,705
[1]	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
[2]	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.
[3]	Assets of VEBA.

Employee Benefit Plans_ Amounts

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$ 232,484	$ 257,839
Non-current liabilities	146,459	158,966
Regulatory liabilities	153,041	148,831
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	68,915	78,864
Current liabilities	0	0
Non-current assets	0	0
Non-current liabilities	67,953	78,239
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	1,568	1,486
Non-current assets	0	0
Non-current liabilities	38,651	39,725
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	6,464	7,137
Current liabilities	3,543	3,273
Non-current assets	23	0
Non-current liabilities	39,855	41,002
Regulatory liabilities	$ 3,209	$ 2,983

Employee Benefit Plans_ Accumul

Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 334,923	$ 348,980
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	30,558	30,229
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	48,077	49,042
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	129,729	135,582
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	30,207	29,843
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	13,121	12,809
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	205,194	213,398
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	351	386
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	23,796	25,456
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	$ 11,160	$ 10,777

Employee Benefit Plans_ Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 6,093	$ 5,448	$ 6,433
Interest Cost	15,522	15,852	15,300
Expected return on plan assets	(19,470)	(18,065)	(18,615)
Amortization of prior service cost	58	62	63
Recognition of net actuarial loss (gain)	11,037	4,806	12,250
Net periodic benefit expense	13,240	8,103	15,431
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,380	1,498	1,392
Interest Cost	1,455	1,447	1,328
Expected return on plan assets	0	0	0
Amortization of prior service cost	2	2	2
Recognition of net actuarial loss (gain)	1,081	498	793
Net periodic benefit expense	3,918	3,445	3,515
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,808	1,700	1,674
Interest Cost	1,801	1,919	1,669
Expected return on plan assets	(131)	(85)	(79)
Amortization of prior service cost	(428)	(428)	(500)
Recognition of net actuarial loss (gain)	408	160	482
Net periodic benefit expense	$ 3,458	$ 3,266	$ 3,246

Employee Benefit Plans_ Accu121

Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Net (gain) loss	$ 8,777	$ 10,996
Prior service cost (gain)	41	51
Total AOCI	8,818	11,047
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	4,663
Prior service cost (credit)	38
Total net periodic benefit cost expected to be recognized during calendar year 2016	4,701
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	6,339	8,396
Prior service cost (gain)	6	8
Total AOCI	6,345	8,404
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	539
Prior service cost (credit)	1
Total net periodic benefit cost expected to be recognized during calendar year 2016	540
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	1,704	1,904
Prior service cost (gain)	(1,087)	(1,218)
Total AOCI	617	$ 686
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	221
Prior service cost (credit)	(278)
Total net periodic benefit cost expected to be recognized during calendar year 2016	$ (57)

Employee Benefit Plans_ Defined

Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.75%
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	$ 2,471
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(2,088)
Effect of One Percentage Point Increase on Service and Interest Cost Components	173
Effect of One Percentage Point Decrease on Service and Interest Cost Components	$ (141)
Healthcare trend rate pre-65 | Black Hills Corporation [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.35%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,024		2,027
Healthcare trend rate pre-65 | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.35%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,024		2,027
Healthcare trend rate pre-65 | Cheyenne Light [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.35%		7.50%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,024		2,027
Healthcare trend rate post-65 | Black Hills Corporation [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.20%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,023		2,024
Healthcare trend rate post-65 | Black Hills Utility Holdings [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.20%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,023		2,024
Healthcare trend rate post-65 | Cheyenne Light [Member]
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.20%		6.25%
Ultimate trend rate	4.50%		4.50%
Year Ultimate Trend Reached	2,023		2,024
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.92%		3.64%	4.21%
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	3.98%		4.68%	3.88%
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	3.30%		3.75%	3.00%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	4.26%		3.92%	4.62%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	3.00%		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	3.70%		4.45%	3.65%
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	3.65%		4.25%	3.50%
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	4.40%		5.15%	4.40%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	4.59%		4.20%	5.05%
Rate of Increase in Compensation Levels	3.52%		3.78%	3.78%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.75%	[1]	6.75%	7.25%
Rate of Compensation Increase	3.78%		3.78%	3.78%
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	4.25%		5.10%	4.35%
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	4.15%		5.00%	4.25%
[1]	The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

Employee Benefit Plans_ Project

Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2015USD ($)
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	$ 15,700
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	16,666
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	17,620
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	18,809
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	19,764
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	113,480
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	1,568
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,628
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,682
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,808
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,539
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	10,024
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	4,270
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	4,337
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	4,331
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	4,309
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	4,292
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 19,552

Commitments and Contingencie124

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	$ 165,484
2,017	133,534
2,018	82,703
2,019	49,196
2,020	48,966
Thereafter	$ 130,745
Purchase Commitment [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase of Fuel, Date of Contract Expiration	Dec. 31, 2017
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]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased | MW	50
Cost of Purchased Power	$ 13,990	$ 13,943	$ 13,026
PacifiCorp Transmission [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased | MW	50
Cost of Purchased Power	$ 1,213	1,227	1,384
Happy Jack Wind Purchase Power Agreeement [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 3, 2028
Megawatts of Capacity Purchased | MW	30
Happy Jack Wind Purchase Power Agreeement [Member] | Renewable Wind Energy, Cheyenne Light [Member]
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power	$ 3,155	3,919	3,772
Silver Sage Wind Power Purchase Agreement [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 30, 2029
Megawatts of Capacity Purchased | MW	30
Silver Sage Wind Power Purchase Agreement [Member] | Renewable Wind Energy, Cheyenne Light [Member]
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power	$ 4,107	4,798	4,809
Busch Ranch Wind Farm [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Oct. 16, 2037
Megawatts of Capacity Purchased | MW	14.5
Cost of Purchased Power	$ 1,734	1,998	1,856
Cargill Power Purchase Agreement [Member]
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power	$ 16,112	$ 9,286	$ 12,291

Commitments And Contingencies_

Commitments And Contingencies: Short-term Purchase Agreement (Details) - Cargill Power Purchase Agreement [Member]	12 Months Ended
	Dec. 31, 2015MW
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Short-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2016
Number of Megawatts Capacity Purchased	50

Commitments And Contingencie126

Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility [Member] - Purchase Option, Property [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Megawatts Capacity Purchased | MW	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2022
Asset Purchase Option | $	$ 2.6

Commitments And Contingencie127

Commitments And Contingencies: Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2015MW
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, 10 Megawatts [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	May 31, 2023
Purchase Power Contract, MEAN, 10 Megawatts [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 Contingencie128

Commitments And Contingencies: Build Transfer Agreement (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Guarantor, Maximum Exposure	$ 159,491
Peak View Wind Project [Member]
Long-term Purchase Commitment, Amount	109,000
Performance Guarantee [Member] | Electric Utilities [Member] | Peak View Wind Project [Member]
Guarantor, Maximum Exposure	$ 89,718	[1]
[1]	BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements.

Commitments And Contingencie129

Commitments And Contingencies: Related Party Lease (Details) - Power purchased [Member] - Pueblo Airport Generation [Member]	12 Months Ended
	Dec. 31, 2015MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Lease Expiration Date	Dec. 31, 2031
Number of Megawatts Capacity Purchased	200

Commitments And Contingencie130

Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt		$ 544,756	$ 544,753
Industrial Development Revenue Bonds Due 2027 [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 10,000	10,000
Long-term Debt, Maturity Date		Mar. 1, 2027
Industrial Development Revenue Bonds Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	$ 7,000	$ 7,000
Long-term Debt, Maturity Date		Sep. 1, 2021
[1]	Variable interest rate.

Commitments And Contingencie131

Commitments And Contingencies: Environmental Contingencies (Details) $ in Millions	Dec. 31, 2015USD ($)
Electric Utilities [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 3.9
Manufactured Gas Plant [Member] | Gas Utilities [Member]
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.4
Loss Contingency, Range of Possible Loss, Minimum	2.9
Loss Contingency, Range of Possible Loss, Maximum	6.1
Accrual for Environmental Loss Contingencies, Gross	$ 2.6

Guarantees (Details)

Guarantees (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Guarantor Obligations [Line Items]
Guarantor Obligations, Term	12/31/2016
Guarantor, Maximum Exposure	$ 159,491
Coal Mining [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Term	Ongoing
Guarantor, Maximum Exposure	$ 69,773	[1]
Electric Utilities [Member] | Performance Guarantee [Member] | Peak View Wind Project [Member]
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	89,718	[2]
Source Gas [Member]
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 1,890,000
[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.
[2]	BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements.

Oil and Gas Reserves (Unaudi133

Oil and Gas Reserves (Unaudited): Oil and Gas Narrative (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)aGross-WellPUD_LocationMcfeState
Reserve Quantities [Line Items]
Wells in Process of Drilling | Gross-Well	1,006
Gas and Oil Acreage, Leased | a	236,545
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	27
Reserves Replaced	209.00%
Proved Undeveloped Reserves, Revisions of Previous Estimates	(10.1)
Proved Undeveloped Reserve Locations | PUD_Location	(6)
Proved Undeveloped Reserves	(0.1)
PUD Developed, PUD location | PUD_Location	(6)
Capital Expenditure for Proved Undeveloped Reserve | $	$ (25.3)
Proved Developed Reserves (Energy)	(6.6)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (0.4)
PUD Locations in Reserves for Five Or More Years | PUD_Location	0
Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(34)
Proved Undeveloped Reserves	(12.1)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (41.9)
Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Proved Undeveloped Reserves	0
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ 0
Reserves Dropped [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(22)
Proved Undeveloped Reserves	(5.4)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (16.1)
Commodity Prices [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	(20.1)
Oil and Gas Well Performance [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	3.6
Oil and Gas Reserve Revisions, Economics [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	6.9
Proved Undeveloped Reserve Locations | PUD_Location	28
Oil and Gas Reserve Revisions, Five Year Reserve Aging Limit [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(6)
PUD Developed, PUD location | PUD_Location	(3)
Capital Expenditure for Proved Undeveloped Reserve | $	$ (0.3)
Proved Developed Reserves (Energy)	0
Williston Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(30)
Proved Undeveloped Reserves	(1.1)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (5.4)
Williston Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Proved Undeveloped Reserves	0
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ 0
Williston Basin [Member] | Reserves Dropped [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(21)
Proved Undeveloped Reserves	(1)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (4.6)
Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	25.9
PUD Developed, PUD location | PUD_Location	(2)
Capital Expenditure for Proved Undeveloped Reserve | $	$ (12)
Proved Developed Reserves (Energy)	(4.6)
Piceance Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(3)
Proved Undeveloped Reserves	(9)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (23.5)
Piceance Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Proved Undeveloped Reserves	0
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ 0
Piceance Basin [Member] | Reserves Dropped [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(1)
Proved Undeveloped Reserves	(4.4)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (11.5)
Piceance Basin [Member] | Oil and Gas Reserve Revisions, Reserves Sold [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Proved Undeveloped Reserves	0
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (0.1)
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	1.2
PUD Developed, PUD location | PUD_Location	(1)
Capital Expenditure for Proved Undeveloped Reserve | $	$ (13)
Proved Developed Reserves (Energy)	(2)
Powder River Basin [Member] | Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	(1)
Proved Undeveloped Reserves	(2)
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ (13)
Powder River Basin [Member] | Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations | PUD_Location	0
Proved Undeveloped Reserves	0
Estimated Future Development Costs of Proved Undeveloped Wells | $	$ 0
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Entity Operates | State	10

Oil and Gas Reserves (Unaudi134

Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Oil and Gas [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved Reserves	$ 1,407	$ 4,881	$ 234
Unproved Reserves	669	5,056	6,022
Exploration Costs	35,434	54,355	12,817
Development Costs	128,998	52,262	48,641
Asset Retirement Obligation Incurred	566	68	143
Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 167,074	$ 116,622	$ 67,857

Oil and Gas Reserves (Unaudi135

Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details)		12 Months Ended
		Dec. 31, 2015$ / bbl$ / MMcfMBblsMMcf	Dec. 31, 2014$ / bbl$ / MMcfMBblsMMcf	Dec. 31, 2013$ / bbl$ / MMcfMBblsMMcf
Proved Developed And Undevleoped Reserves [Roll Forward]
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl		50.28	94.99	96.94
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf		2.59	4.35	3.67
Average Natural Gas Liquids Price Per MCF, NYMEX | $ / MMcf	[1]	0	0
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl		44.72	85.80	89.79
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf		1.27	3.33	3.45
Average Natural Gas Liquids Price Per MCF, Wellhead | $ / MMcf		18.96	34.81
Oil [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year | MBbls		4,276	3,921	4,116
Production | MBbls		(371)	(337)	(336)	[2]
Additions, Acquisitions (Sales) | MBbls		(11)	(40)	(30)
Additions, Extensions, Discoveries (bcfe) | MBbls		199	733	379
Reserves, Revisions of Previous Estimates | MBbls		(643)	(1)	(208)
Balance at End of Year | MBbls		3,450	4,276	3,921
Proved Developed Reserves (Volume) | MBbls		3,436	3,780	3,689
Proved Undeveloped Reserve (Volume) | MBbls		14	496	232
Natural Gas [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year		65,440	63,190	55,985
Production		(10,058)	(7,156)	(6,984)	[2]
Additions, Acquisitions (Sales)		(828)	(61)	(46)
Additions, Extensions, Discoveries (bcfe)		24,462	11,003	10,456
Reserves, Revisions of Previous Estimates		(5,604)	(1,536)	3,779
Balance at End of Year		73,412	65,440	63,190
Proved Developed Reserves (Volume)		73,390	57,427	60,224
Proved Undeveloped Reserve (Volume)		22	8,013	2,966
Natural Gas Liquids [Member]
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year		1,720	0
Production		(102)	(135)
Additions, Acquisitions (Sales)		0	0
Additions, Extensions, Discoveries (bcfe)		232	182
Reserves, Revisions of Previous Estimates		(98)	1,673
Balance at End of Year		1,752	1,720	0
Proved Developed Reserves (Volume)		1,752	1,530
Proved Undeveloped Reserve (Volume)		0	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, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Presently, ethane is not being recovered at any of the facilities that process our natural gas production.
[2]	Production for reserve calculations does not include volumes for natural gas liquids (NGLs) for historical periods.

Oil and Gas Reserves (Unaudi136

Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Unproved oil and gas properties	$ 47,254	$ 75,329	$ 62,553
Proved oil and gas properties	1,008,466	807,518	725,345
Gross capitalized costs	1,055,720	882,847	787,898
Accumulated depreciation, depletion and amortization and valuation allowances	(888,775)	(612,012)	(592,505)
Net capitalized costs	$ 166,945	$ 270,835	$ 195,393

Oil and Gas Reserves (Unaudi137

Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenue	$ 43,283	$ 55,114	$ 54,884
Production costs	19,762	22,155	20,140
Depreciation, depletion and amortization and valuation provisions	28,062	23,288	16,717
Impairment of long-lived assets	249,608	0	0
Total costs	297,432	45,443	36,857
Results of operations from producing activities before tax	(254,149)	9,671	18,027
Income tax benefit (expense)	93,743	(3,415)	(6,308)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$ (160,406)	$ 6,256	$ 11,719

Oil and Gas Reserves (Unaudi138

Oil and Gas Reserves (Unaudited): Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	$ 19,170
Exploration cost	45,929
Capitalized interest	3,008
Total	68,107
Current Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	4,256
Exploration cost	37,770
Capitalized interest	940
Total	42,966
Prior Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	4,475
Exploration cost	8,159
Capitalized interest	351
Total	12,985
More Than One Year, Less Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	9,006
Exploration cost	0
Capitalized interest	736
Total	9,742
More Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	1,433
Exploration cost	0
Capitalized interest	981
Total	2,414
Oil and Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 1,000	$ 1,000	$ 1,100

Oil and Gas Reserves (Unaudi139

Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 295,173	$ 675,973	$ 602,501
Future production costs	(146,552)	(245,180)	(213,578)
Future development costs, including plugging and abandonment	(24,833)	(45,123)	(40,557)
Future income tax expense	0	(29,523)	(81,566)
Future net cash flows	123,788	356,147	266,800
10% annual discount for estimated timing of cash flows	(44,760)	(173,125)	(107,375)
Standardized measure of discounted future net cash flows	$ 79,028	$ 183,022	$ 159,425	$ 136,103

Oil and Gas Reserves (Unaudi140

Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 183,022	$ 159,425	$ 136,103
Sales and transfers of oil and gas produced, net of production costs	(29,948)	(32,139)	(35,932)
Net changes in prices and production costs	(127,199)	(28,544)	15,126
Extensions, discoveries and improved recovery, less related costs	15,718	17,582	29,574
Changes in future development costs	(7,387)	3,195	(12,216)
Development costs incurred during the period	27,211	2,079	3,554
Revisions of previous quantity estimates	(6,941)	23,722	12,851
Accretion of discount	18,870	18,437	15,126
Net change in income taxes	5,682	19,265	(3,892)
Purchases of reserves	0	0	0
Sales of reserves	0	0	(869)
Standardized measure - end of year	$ 79,028	$ 183,022	$ 159,425

Discontinued Operations (Detail

Discontinued Operations (Details) - Energy Marketing [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Date	Feb. 29, 2012
Proceeds from sale of business operations		$ 108,000
Funds Retained, Sale of Business		$ 58,000
Disposal Group, Including Discontinued Operation, Revenue	$ 0
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	(1,391)
Discontinued Operation, Tax Effect of Discontinued Operation	507
Income (loss) from discontinued operations, net of tax	(884)
Minimum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Post Close Adjustment	$ 1,100

Quarterly Historical Data (U142

Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Line Items]
Revenue	$ 318,259	$ 272,105	$ 272,254	$ 441,987	$ 378,077	$ 272,087	$ 283,237	$ 460,169	$ 1,304,605	$ 1,393,570	$ 1,275,852
Operating income (loss)	197	(2,044)	(38,858)	70,500	70,786	55,238	47,412	90,432	29,795	263,868	259,445
Income (loss) from continuing operations	(14,176)	(9,943)	(41,842)	33,850	34,534	27,363	20,347	48,645	(32,111)	130,889	118,307
Net income (loss) available for common stock	$ (14,176)	$ (9,943)	$ (41,842)	$ 33,850	$ 34,534	$ 27,363	$ 20,347	$ 48,645	$ (32,111)	$ 130,889	$ 117,423
Total income (loss) per share, Basic (usd per share)	$ (0.30)	$ (0.22)	$ (0.94)	$ 0.76	$ 0.78	$ 0.61	$ 0.46	$ 1.10	$ (0.71)	$ 2.95	$ 2.66
Total income (loss) per share, Diluted (usd per share)	(0.30)	(0.22)	(0.94)	0.76	0.77	0.61	0.46	1.09	(0.71)	2.93	2.64
Dividends per share paid (usd per share)	0.405	0.405	0.405	0.405	0.390	0.390	0.390	0.390	$ 1.62	$ 1.56	$ 1.52
Common Stock [Member] | Maximum [Member]
Selected Quarterly Financial Information [Line Items]
Share Price (usd per share)	47.51	47.27	52.96	53.37	57.17	62.13	61.41	59.05
Common Stock [Member] | Minimum [Member]
Selected Quarterly Financial Information [Line Items]
Share Price (usd per share)	$ 40	$ 36.81	$ 43.48	$ 47.88	$ 47.11	$ 47.87	$ 55.23	$ 51.09

Subsequent Event_ Completion of

Subsequent Event: Completion of Acquisition (Details) $ in Millions	Feb. 12, 2016USD ($)
Source Gas [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Combination, Purchase Price	$ 1,890

Subsequent Event_ Sale of Non-c

Subsequent Event: Sale of Non-controlling Interest in Subsidiary (Details) - Subsequent Event [Member] $ in Millions	Feb. 12, 2016USD ($)
Subsequent Event [Line Items]
Ownership Percentage by Noncontrolling Owner	49.90%
Sale of Ownership Interest by Parent	$ 215

Subsequent Event_ Financing Act

Subsequent Event: Financing Activities (Details) - USD ($) $ in Thousands		Jan. 20, 2016	Jan. 13, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsequent Event [Line Items]
Long-term debt - issuance				$ 300,000	$ 160,000	$ 800,000
Black Hills Corporation [Member]
Subsequent Event [Line Items]
Long-term Debt				1,322,110	$ 997,836
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Subsequent Event [Line Items]
Notional amount	[1]			$ 250,000
All-in rate				2.29%
Subsequent Event [Member]
Subsequent Event [Line Items]
Long-term debt - issuance			$ 546,000
Subsequent Event [Member] | Black Hills Corporation [Member]
Subsequent Event [Line Items]
Long-term Debt			550,000
Subsequent Event [Member] | Black Hills Corporation [Member] | Senior Unsecured Notes Due 2026 [Member]
Subsequent Event [Line Items]
Long-term Debt			$ 300,000
Fixed interest rate			3.95%
Debt instrument term			10 years
Subsequent Event [Member] | Black Hills Corporation [Member] | Senior Unsecured Notes Due 2019 [Member]
Subsequent Event [Line Items]
Long-term Debt			$ 250,000
Fixed interest rate			2.50%
Debt instrument term			3 years
Subsequent Event [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Subsequent Event [Line Items]
Derivative term		10 years
Notional amount		$ 150,000
All-in rate		2.09%
[1]	These swaps are designated as cash flow hedges of anticipated debt refinancings.

Schedule II Consolidated Val146

Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for Doubtful Accounts, Balance at Beginning of Year	$ 1,516	$ 1,237	$ 768
Allowance for Doubtful Accounts, Adjustments	0	0	0
Allowance for Doubtful Accounts, Charged to Cost and Expense	3,860	4,470	2,780
Allowance for Doubtful Accounts, Recoveries and Other Additions	4,132	4,233	4,999
Allowance for Doubtful Accounts, Write-Offs and Other Deductions	(7,767)	(8,424)	(7,310)
Allowance for Doubtful Accounts, Balance at End of Year	$ 1,741	$ 1,516	$ 1,237