View Filing Data

456,887

581,782

492,147

Non-regulated energy operations and maintenance

272,407

270,954

261,919

88,702

88,141

83,762

155,370

144,745

137,324

Taxes - property, production and severance

249,608

^[1]

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

Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)

29,795

263,868

259,445

Interest charges -

(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

30,169

Allowance for funds used during construction - equity

1,621

1,925

1,723

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)

(4,405)

^[1]

22,160

(66,625)

(63,040)

Income (loss) from discontinued operations, net of tax

(32,111)

130,889

118,307

(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)

0.00

(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)

0.00

(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 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 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 - 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 (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 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 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 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.

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 exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. The 5-year term represents the maximum forward term hedged.

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

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

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

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

Bond Issue Costs - Bond issue costs are recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue.

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

Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. This regulatory treatment was applied to the tax benefit generated by repair costs that were previously capitalized for tax purposes in a rate case settlement that was reached with respect to Black Hills Power in 2010. In this instance, the agreed upon rate increase was less than it would have been absent the flow-through treatment. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered repairs for tax purposes, but are capitalized for book purposes.

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

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

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

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

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

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

We use the 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. See Note 15 for additional information.

Earnings per Share of Common Stock

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

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



	December 31, 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

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

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

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

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.

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.

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

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Property, Plant and Equipment [Abstract]

Property, Plant And Equipment:

12 Months Ended

Dec. 31, 2015

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:

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:

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.

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

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Long-term Debt, Unclassified [Abstract]

Long-Term Debt:

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

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:

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):

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:

Asset Retirement Obligations:

12 Months Ended

Dec. 31, 2015

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:

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.

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

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Fair Value Measurements:

12 Months Ended

Dec. 31, 2015

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 Instruments:

12 Months Ended

Dec. 31, 2015

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.

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

Stockholders' Equity Note [Abstract]

Stock:

12 Months Ended

Dec. 31, 2015

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		Weighted-Average Grant Date Fair Value^(a)		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.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187143-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

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

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Statement of Comprehensive Income [Abstract]

Impairment Of Assets:	12 Months Ended
Impairment Of Assets:	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:

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:

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:

12 Months Ended

Dec. 31, 2015

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
	Location on the Consolidated Statements of Income (Loss)	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	)

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash flow Information:

12 Months Ended

Dec. 31, 2015

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:

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:

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, SO₂, NO_x, mercury, hazardous air pollutants, particulate matter and GHG. Power generating facilities burning fossil fuels emit each of the foregoing pollutants and, therefore, are subject to substantial regulation and enforcement oversight by various governmental agencies.

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

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):

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:

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.

The entire disclosure related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

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Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited):

12 Months Ended

Dec. 31, 2015

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:	12 Months Ended
Subsequent Event:	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 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)	12 Months Ended
Business Description (Policies)	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)

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)

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):

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 (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 (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)

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

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

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Schedule of Short-term Debt

Notes Payable (Tables)

12 Months Ended

Dec. 31, 2015

Notes Payable [Abstract]

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

Deferred Financing Costs

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



	Deferred Financing Costs Remaining 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:

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 (Tables)

12 Months Ended

Dec. 31, 2015

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.

Schedule of Derivative Instruments



	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]

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.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

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



	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 Instruments (Tables)

12 Months Ended

Dec. 31, 2015

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 (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)

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		Weighted-Average Grant Date Fair Value^(a)		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)

12 Months Ended

Dec. 31, 2015

Leases, Operating [Abstract]

Operating Leases of Lessor Disclosure



	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)

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)

(c)

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



	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) (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
	Location on the Consolidated Statements of Income (Loss)	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 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)

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)

(b)

Schedule of Changes in Projected Benefit Obligations

Benefit Obligations



		Defined Benefit Pension Plans						Supplemental Non-qualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
		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



	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



	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

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 (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)

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)

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

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

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

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Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Energy Marketing [Member]

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2015

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal Groups, Including Discontinued Operations [Table Text Block]



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	)

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

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

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 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 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 Significant Accounting Policies: Goodwill (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

$ 353,396

6,363

359,759

353,396

250,487

6,363

^[1]

256,850

250,487

8,765

Aquila Transaction [Member] | Electric Utilities [Member]

$ 8,765

8,765

Goodwill [Line Items]

Goodwill Allocation by Segment (percentage)

72.00%

Aquila Transaction [Member] | Gas Utilities [Member]

$ 246,000

Goodwill [Line Items]

Goodwill Allocation by Segment (percentage)

28.00%

$ 94,144

94,144

Organization, Consolidation and Presentation of Financial Statements [Abstract]

$ 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 Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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

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 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]

$ 232,484

$ 257,839

Deferred energy, fuel and gas cost adjustments [Member]

$ 153,041

148,831

Schedule of Regulatory Assets and Liabilities [line items]

1 year

Employee benefit plans [Member]

^[1]

$ 7,814

6,496

Schedule of Regulatory Assets and Liabilities [line items]

12 years

Schedule of Regulatory Assets and Liabilities [line items]

^[2]

$ 47,218

53,139

Cost of removal [Member]

44 years

Other regulatory liabilities [Member]

^[1]

$ 90,045

78,249

Schedule of Regulatory Assets and Liabilities [line items]

25 years

Deferred energy, fuel and gas cost adjustments [Member]

^[2]

$ 7,964

10,947

Schedule of Regulatory Assets and Liabilities [line items]

1 year

Deferred gas cost adjustments and gas price derivatives [Member]

^[1],[3]

$ 24,751

23,820

Schedule of Regulatory Assets and Liabilities [line items]

2 years

Gas price derivative [Member]

^[1],[3]

$ 15,521

37,471

Schedule of Regulatory Assets and Liabilities [line items]

5 years

Allowance For Funds Used During Construction [Member]

^[1]

$ 23,583

18,740

Schedule of Regulatory Assets and Liabilities [line items]

45 years

Employee benefit plans [Member]

^[4]

$ 12,870

12,358

Schedule of Regulatory Assets and Liabilities [line items]

12 years

Schedule of Regulatory Assets and Liabilities [line items]

^[2]

$ 83,986

97,126

Environmental [Member]

Asset retirement obligations [Member]

^[1]

$ 1,180

1,314

Schedule of Regulatory Assets and Liabilities [line items]

44 years

Bond issuance cost [Member]

^[1]

$ 457

3,287

Schedule of Regulatory Assets and Liabilities [line items]

22 years

Renewable energy standard adjustment [Member]

^[1]

$ 3,133

3,276

Schedule of Regulatory Assets and Liabilities [line items]

5 years

Flow through accounting [Member]

^[1]

$ 5,068

9,622

Schedule of Regulatory Assets and Liabilities [line items]

35 years

Decommissioning costs [Member]

^[2]

$ 29,722

25,887

Schedule of Regulatory Assets and Liabilities [line items]

10 years

Other regulatory assets [Member]

^[4]

$ 18,310

12,484

Schedule of Regulatory Assets and Liabilities [line items]

15 years

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

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)
$ in Thousands

12 Months Ended

Feb. 12, 2016

USD ($)

utility

customer

Jan. 13, 2016

USD ($)

Nov. 23, 2015

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

Jul. 12, 2015

USD ($)

Subsequent Event [Member]

$ 300,000

$ 160,000

$ 800,000

Issuance of common stock

254,581

Equity units - issuance

$ 290,030

290,030

$ 0

$ 546,000

Black Hills Corporation [Member] | Subsequent Event [Member]

1,322,110

997,836

Senior Unsecured Notes Due 2026 [Member] | Black Hills Corporation [Member] | Subsequent Event [Member]

550,000

$ 300,000

3.95%

Senior Unsecured Notes Due 2019 [Member] | Black Hills Corporation [Member] | Subsequent Event [Member]

10 years

$ 250,000

2.50%

Remarketable Junior Subordinated Notes Due 2028 [Member]

3 years

Debt Instrument, Convertible, Number of Equity Instruments | shares

5,980,000

Remarketable Junior Subordinated Notes Due 2028 [Member] | Black Hills Corporation [Member]

$ 299,000

^[1]

$ 0

3.50%

^[1]

Common Stock [Member]

Issuance of common stock, shares | shares

6,325,000.000

6,325,000

Issuance of common stock

$ 246,000

$ 6,325

Source Gas [Member]

Source Gas [Member] | Subsequent Event [Member]

Bridge Loan

$ 1,170,000

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

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 Equipment (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Less: accumulated depreciation, depletion and amortization

$ 4,976,778

$ 4,563,400

1,717,684

1,357,929

3,259,094

3,205,471

376

5,524

15,377

5,196

15,753

10,720

Corporate, Non-Segment [Member] | Weighted Average [Member]

$ 20,523

$ 14,205

Corporate, Non-Segment [Member] | Minimum [Member]

10 years

11 years

Corporate, Non-Segment [Member] | Maximum [Member]

5 years

Intercompany Eliminations [Member]

30 years

Less: accumulated depreciation, depletion and amortization

^[1]

$ (4,770)

$ (3,485)

Non Regulated Energy Group [Member]

1,444,127

1,261,793

5,831

6,010

Less: accumulated depreciation, depletion and amortization

1,449,958

1,267,803

1,075,042

784,973

374,916

482,830

Plant acquisition adjustment

1,136,847

1,125,845

Transmission

301,280

284,032

Distribution

785,351

718,342

^[2]

4,870

General

180,840

152,982

Capital lease - plant in service

^[3]

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

Less: accumulated depreciation, depletion and amortization

^[4]

2,769,547

2,597,212

540,634

484,406

Depreciation, depletion and amortization, remaining amortization period

$ 2,228,913

$ 2,112,806

15 years

Electric Utilities [Member] | Weighted Average [Member] | Production, Electric [Member]

Electric Utilities [Member] | Weighted Average [Member] | Electric transmission [Member]

43 years

45 years

Electric Utilities [Member] | Weighted Average [Member] | Electric distribution [Member]

52 years

49 years

Electric Utilities [Member] | Weighted Average [Member] | Plant acquisition adjustment [Member]

48 years

44 years

Electric Utilities [Member] | Weighted Average [Member] | General [Member]

32 years

Electric Utilities [Member] | Weighted Average [Member] | Capital lease - plant in service [Member]

24 years

21 years

Electric Utilities [Member] | Minimum [Member] | Production, Electric [Member]

20 years

Electric Utilities [Member] | Minimum [Member] | Electric transmission [Member]

25 years

Electric Utilities [Member] | Minimum [Member] | Electric distribution [Member]

40 years

Electric Utilities [Member] | Minimum [Member] | Plant acquisition adjustment [Member]

15 years

Electric Utilities [Member] | Minimum [Member] | General [Member]

32 years

Electric Utilities [Member] | Minimum [Member] | Capital lease - plant in service [Member]

3 years

Electric Utilities [Member] | Maximum [Member] | Production, Electric [Member]

20 years

Electric Utilities [Member] | Maximum [Member] | Electric transmission [Member]

65 years

Electric Utilities [Member] | Maximum [Member] | Electric distribution [Member]

70 years

Electric Utilities [Member] | Maximum [Member] | Plant acquisition adjustment [Member]

75 years

Electric Utilities [Member] | Maximum [Member] | General [Member]

32 years

Electric Utilities [Member] | Maximum [Member] | Capital lease - plant in service [Member]

65 years

20 years

Total plant in service before construction work in progress

$ 13

Transmission

24,081

24,090

Distribution

607,224

557,405

General

100,765

90,085

732,083

671,593

Construction work in progress

9,437

16,072

Less: accumulated depreciation, depletion and amortization

741,520

687,665

106,778

92,035

Gas Utilities [Member] | Weighted Average [Member] | General [Member]

$ 634,742

$ 595,630

Gas Utilities [Member] | Weighted Average [Member] | Production, Gas [Member]

21 years

19 years

Gas Utilities [Member] | Weighted Average [Member] | Gas transmission [Member]

30 years

37 years

Gas Utilities [Member] | Weighted Average [Member] | Gas distribution [Member]

62 years

54 years

Gas Utilities [Member] | Minimum [Member] | General [Member]

44 years

46 years

Gas Utilities [Member] | Minimum [Member] | Production, Gas [Member]

16 years

Gas Utilities [Member] | Minimum [Member] | Gas transmission [Member]

30 years

Gas Utilities [Member] | Minimum [Member] | Gas distribution [Member]

53 years

Gas Utilities [Member] | Maximum [Member] | General [Member]

41 years

Gas Utilities [Member] | Maximum [Member] | Production, Gas [Member]

22 years

Gas Utilities [Member] | Maximum [Member] | Gas transmission [Member]

30 years

Gas Utilities [Member] | Maximum [Member] | Gas distribution [Member]

70 years

56 years

$ 156,721

$ 153,779

2,182

2,262

Less: accumulated depreciation, depletion and amortization

^[4]

158,903

156,041

51,471

47,704

Power Generation [Member] | Weighted Average [Member]

$ 107,432

$ 108,337

Power Generation [Member] | Minimum [Member]

33 years

Power Generation [Member] | Maximum [Member]

2 years

40 years

$ 154,630

$ 145,619

3,649

3,748

Less: accumulated depreciation, depletion and amortization

158,279

149,367

97,663

90,629

Coal Mining [Member] | Weighted Average [Member]

$ 60,616

$ 58,738

Coal Mining [Member] | Minimum [Member]

13 years

15 years

Coal Mining [Member] | Maximum [Member]

2 years

59 years

$ 1,132,776

$ 962,395

Less: accumulated depreciation, depletion and amortization

1,132,776

962,395

925,908

646,640

Oil and Gas [Member] | Weighted Average [Member]

$ 206,868

$ 315,755

Oil and Gas [Member] | Minimum [Member]

24 years

Oil and Gas [Member] | Maximum [Member]

3 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 (Details) $ in Thousands	Dec. 31, 2015 USD ($)
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: Segment Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

$ 4,655,501

$ 4,245,902

584,745

106,605

^[1]

2,859,720

2,748,680

864,858

906,922

^[1]

60,864

76,945

76,358

74,407

$ 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 Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 458,821

$ 391,267

^[1]

9,864

9,046

^[1]

202,075

193,199

^[1]

69,496

70,528

^[1]

2,694

2,379

^[1]

5,767

6,676

^[1]

$ 168,925

$ 109,439

[1]	Includes accruals for property, plant and equipment.

Business Segments Information: Property, Plant and Equipment (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

$ 4,976,778

$ 4,563,400

15,753

10,720

^[1]

2,769,547

2,597,212

741,520

687,665

^[1]

158,903

156,041

158,279

149,367

$ 1,132,776

$ 962,395

[1]

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

$ 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

456,887

581,782

492,147

412,945

403,175

386,936

155,370

144,745

137,324

249,608

^[1]

$ 197

$ (2,044)

$ (38,858)

$ 70,500

$ 70,786

$ 55,238

$ 47,412

$ 90,432

29,795

263,868

259,445

(83,719)

(70,960)

(111,788)

^[2]

30,169

1,621

1,925

1,723

2,437

2,681

1,798

(4,405)

^[1]

22,160

(66,625)

(63,040)

(32,111)

130,889

118,307

712,387

683,201

651,445

291,563

314,573

294,048

173,810

165,641

159,961

84,284

79,424

77,704

174,347

137,673

133,595

(57,712)

(53,402)

(61,537)

4,236

4,615

5,277

1,225

1,164

633

(42,792)

(30,498)

(25,834)

79,304

59,552

52,134

507,139

617,768

539,689

277,491

380,852

310,463

127,837

132,635

126,073

28,971

26,499

26,381

72,840

77,782

76,772

(15,359)

(15,725)

(25,234)

479

441

976

532

(60)

(20,685)

(20,663)

(19,747)

37,807

41,869

32,707

7,483

6,401

4,648

32,140

33,126

30,186

4,329

4,540

5,091

54,321

49,892

47,760

(4,218)

(4,351)

(21,178)

^[2]

1,015

682

785

(6)

(18,539)

(17,701)

(11,080)

32,650

28,516

16,288

34,313

31,086

25,186

41,630

41,172

39,519

9,806

10,276

11,523

13,630

11,910

5,586

(433)

(493)

(641)

2,247

2,275

2,304

(3,608)

(3,299)

(932)

11,870

10,452

6,327

43,283

55,114

54,884

41,593

42,659

40,365

29,287

24,246

17,877

^[1]

249,608

(277,205)

(11,791)

(3,358)

(2,726)

(2,603)

(2,253)

217

918

1,639

(337)

183

108

^[1]

(4,405)

104,498

4,768

2,113

Intercompany Eliminations [Member]

(179,958)

(8,525)

(1,751)

(353,385)

(349,999)

(344,314)

(112,289)

(113,759)

(112,489)

(229,786)

(225,473)

(211,977)

(10,580)

(7,930)

(12,876)

(730)

(2,837)

(6,972)

54,568

55,913

84,250

(52,942)

(53,759)

(76,724)

(72,190)

(62,574)

(42,641)

360

744

218

Intercompany Eliminations [Member] | Electric Utilities [Member]

(70,934)

(62,513)

(41,869)

Intercompany Eliminations [Member] | Gas Utilities [Member]

11,617

14,110

13,863

Intercompany Eliminations [Member] | Power Generation [Member]

Intercompany Eliminations [Member] | Coal Mining [Member]

83,307

81,157

78,389

Intercompany Eliminations [Member] | Oil and Gas [Member]

30,753

32,272

31,442

Operating Segments [Member] | Electric Utilities [Member]

Operating Segments [Member] | Gas Utilities [Member]

724,004

697,311

665,308

Operating Segments [Member] | Power Generation [Member]

507,139

617,768

539,689

Operating Segments [Member] | Coal Mining [Member]

90,790

87,558

83,037

Operating Segments [Member] | Oil and Gas [Member]

65,066

63,358

56,628

43,283

55,114

54,884

227,708

222,460

220,620

122

116

125

225,721

213,415

202,809

9,273

7,690

11,624

(7,408)

1,239

6,062

(57,839)

(50,299)

(85,195)

^[2]

30,169

48,582

48,969

69,760

70,889

61,605

41,453

2,926

(7,778)

Consolidation, Eliminations [Member]

57,150

61,538

54,471

$ 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) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Nov. 23, 2015

Dec. 31, 2014

Oct. 01, 2014

Long-term Debt, including current maturities

$ 1,866,866

$ 1,542,589

Long-term Debt, Current Maturities

(275,000)

Long-term debt, net of current maturities

1,866,866

1,267,589

Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]

$ 544,756

544,753

Electric Utilities [Member] | First Mortgage Bonds Due 2032 [Member]

$ 160,000

Aug. 15, 2032

7.23%

Electric Utilities [Member] | First Mortgage Bonds Due 2039 [Member]

$ 75,000

75,000

Nov. 01, 2039

6.13%

Debt Instrument, Unamortized Discount

$ 180,000

180,000

$ (99)

(102)

Electric Utilities [Member] | First Mortgage Bonds Due 2037 [Member]

Nov. 20, 2037

6.67%

Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2021 [Member]

$ 110,000

110,000

Sep. 01, 2021

^[1]

0.05%

Electric Utilities [Member] | Industrial Development Revenue Bonds Due 2027 [Member]

^[1]

$ 7,000

7,000

Mar. 01, 2027

^[1]

0.05%

Electric Utilities [Member] | Series 94 A Debt, Due 2024 [Member]

^[1]

$ 10,000

10,000

Jun. 01, 2024

^[1]

0.75%

^[1]

$ 2,855

2,855

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2023 [Member]

$ 1,322,110

997,836

Nov. 30, 2023

4.25%

Debt Instrument, Unamortized Discount

$ 525,000

525,000

$ (1,890)

(2,164)

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2020 [Member]

Jul. 15, 2020

5.88%

Black Hills Corporation [Member] | Remarketable Junior Subordinated Notes Due 2028 [Member]

$ 200,000

200,000

^[2]

Nov. 01, 2028

3.50%

^[2]

3.50%

Black Hills Power [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]

$ 299,000

^[2]

$ 299,000

Oct. 20, 2044

4.43%

Cheyenne Light [Member] | Electric Utilities [Member] | First Mortgage Bonds Due 2044 [Member]

$ 85,000

85,000

$ 85,000

Oct. 20, 2044

4.53%

London Interbank Offered Rate (LIBOR) [Member] | Corporate Term Loan due June 2015 [Member]

$ 75,000

75,000

$ 75,000

London Interbank Offered Rate (LIBOR) [Member] | Black Hills Corporation [Member] | Corporate Term Loan Due April 2017 [Member]

$ 275,000

Apr. 12, 2017

^[3]

1.28%

London Interbank Offered Rate (LIBOR) [Member] | Black Hills Corporation [Member] | Corporate Term Loan due June 2015 [Member]

$ 300,000

Jun. 19, 2015

^[3]

1.3125%

$ 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 Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term Debt, Unclassified [Abstract]
2016	$ 0	$ 275,000
2017	300,000
2018	0
2019	0
2020	200,000
After 2020	$ 1,368,855

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 Corporate Term Loan (Details) - USD ($) $ in Millions		12 Months Ended
	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 Financing Costs (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 11,379

Senior Unsecured Notes Due 2023 [Member] [Member]

5,113

$ 1,025

$ 4,262

3,414

Senior Unsecured Notes Due 2014 [Member]

494

653

Senior Unsecured Notes Due 2020 [Member]

635

759

167

Bridge Term Loan

843

Remarketable Junior Subordinated Notes Due 2028 [Member]

4,213

1,567

First Mortgage Bonds Due 2044 [Member] | Black Hills Power [Member]

687

First Mortgage Bonds Due 2044 [Member] | Cheyenne Light [Member]

^[1]

635

First Mortgage Bonds Due 2032 [Member]

^[1]

551

First Mortgage Bonds Due 2039 [Member]

1,809

First Mortgage Bonds Due 2037 [Member]

674

Project Financing Debt Due 2016 [Member]

Deferred Financing Costs, Other [Member]

3,177

^[2]

440

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

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

Notes Payable (Details) $ in Thousands	12 Months Ended
Notes Payable (Details) $ in Thousands	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
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 (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

$ 47,386

$ 51,851

828

413

(4,693)

(1,017)

2,560

2,186

^[1]

(1,346)

(6,047)

^[2]

44,735

47,386

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

7,012

6,922

(2,733)

(85)

183

175

4,462

7,012

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

291

274

(168)

136

291

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

19,138

20,627

345

993

951

^[1]

(1,498)

(2,785)

18,633

19,138

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

20,945

24,028

828

(1,792)

(932)

1,371

1,043

152

(3,262)

^[2]

$ 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 (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2015

USD ($)

MMBTU

bbl

Dec. 31, 2014

USD ($)

MMBTU

bbl

$ 0

3,441

2,835

3,340

156

$ 2,680

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

10,000

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

$ 0

1 year 4 months

Weighted average fixed interest rate

^[1]

$ 250,000

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]

Notional amount - commodities | bbl

^[2]

198,000

334,500

MaximumTerm Hedged in Cash Flow Hedge

^[3]

1 month

$ 0

Natural Gas [Member] | Swap [Member] | Oil and Gas [Member]

$ 0

MaximumTerm Hedged in Cash Flow Hedge

^[2]

4,392,500

6,582,500

^[3]

1 month

$ 0

External Credit Rating, Non Investment Grade [Member]

Credit Exposure, Non-investment Grade Company

1,100

Utilities Group [Member] | Natural Gas, Distribution [Member]

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]

20,580,000

19,370,000

Utilities Group [Member] | Natural Gas, Distribution [Member] | Commodity Option [Member] | Purchase Contract [Member]

^[4]

60 months

72 months

2,620,000

4,020,000

Utilities Group [Member] | Natural Gas, Distribution [Member] | Basis Swap [Member] | Purchase Contract [Member]

^[4]

3 months

8 months

18,150,000

12,005,000

Revolving Credit Facility [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

^[4]

60 months

$ 0

2,835

3,340

$ 156

$ 2,680

1 year

2 years

Weighted average fixed interest rate

^[5]

$ 75,000

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: 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

$ 17,267

Cash Flow Hedging [Member]

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

Cash Flow Hedging [Member] | Interest Rate Swap [Member]

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

Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Interest Expense [Member]

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]

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]

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

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

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

$ (12,902)

^[1]

[1]	These interest rate swaps were settled in the fourth quarter of 2013.

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: 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: 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: 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 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)
$ / shares in Units, shares in Thousands

12 Months Ended

Nov. 23, 2015

USD ($)

$ / shares

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

USD ($)

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

$ 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, Convertible, Conversion Ratio

1.0572

Maximum [Member]

Debt Instrument, Convertible, Conversion Ratio

1.2422

Remarketable Junior Subordinated Notes Due 2028 [Member]

$ 1,322,110,000

997,836,000

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]

RSN Interest Rate

3.50%

^[1]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]

$ 299,000,000

^[1]

$ 0

[1]	See Note 12 for RSN details.

Stock: Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	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	6,325,000.000	6,325,000
Shares issued, price (usd per share)	$ 40.25
Issuance of common stock	$ 246,000	$ 6,325

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 (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Employee Stock Option [Member]

1 year 8 months

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

(5)

Options, Shares - Ending

129

134

Exercisable at end of period

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)

0.00

Forfeited/canceled (usd per share)

54.29

Expired (usd per share)

0.00

Exercised (usd per share)

0.00

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

Intrinsic value of options exercised

425

$ 816

$ 130

^[1]

199

789

Net cash received from exercise of options

237

2,046

Tax benefit realized from exercise of shares

^[2]

$ 0

$ 70

$ 276

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

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 (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)	49.00
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 (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, Performance Shares, Outstanding [Roll Forward]

$ 7,700,000

Performance Shares [Member]

1 year 8 months

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%

Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]

$ 2,200,000

Performance Shares, Number of Shares Authorized, Beginning of Period

Performance Shares, Number of Shares Authorized, End of Period

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

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

$ 1,300,000

Performance Shares, Liability Awards [Member]

1 year 8 months

Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]

Performance Shares, Number of Shares Authorized, Beginning of Period

Performance Shares, Granted in Period

Performance Shares, Forfeited in Period

Performance Shares, Vested in Period

(32)

Performance Shares, Number of Shares Authorized, End of Period

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

Performance Shares, Granted in Period

Performance Shares, Forfeited in Period

Performance Shares, Vested in Period

(32)

Performance Shares, Number of Shares Authorized, End of Period

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]

0.00

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%

Maximum [Member] | Performance Shares [Member]

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

Performance Share Award, Percentage of Target

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

Impairment of Assets (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2015

USD ($)

$ / bbl

$ / MMcf

Dec. 31, 2014

USD ($)

$ / bbl

$ / MMcf

Dec. 31, 2013

USD ($)

$ / bbl

$ / MMcf

Impaired Assets Held and Used [Line Items]

Impairment of long-lived assets | $

$ 249,608

^[1]

$ 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

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 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

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) - USD ($) $ in Thousands	12 Months Ended
Operating Lease (Details) - USD ($) $ in Thousands	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]
2016	2,907
2017	2,491
2018	2,268
2019	1,932
2020	1,238
Thereafter	$ 6,199

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 Tax Assets and Liabilities (Details) - USD ($)
$ in Thousands

Dec. 31, 2015

Dec. 31, 2014

Deferred Tax Assets, Net [Abstract]

Federal net operating loss

$ 43,586

$ 49,243

Employee benefits

26,400

26,714

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)

Mining development and oil exploration

(29,092)

(25,340)

(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 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%

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%)

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%)

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 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 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, 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, 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	2007
Internal Revenue Service (IRS) [Member] \| Maximum [Member]
Tax Credit Carryforward [Line Items]
Income Tax Examination, Year under Examination	2009
Internal Revenue Service (IRS) [Member] \| Settlement with Taxing Authority [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 1,800
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 (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: 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)

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

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: Narrative (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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 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%

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 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 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: 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]

Fair Value, Inputs, Level 3 [Member]

$ 288,622

$ 299,533

$ 280,362

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)

322

Settlements

(6,000)

Balance, end of period

36,889

34,753

Common Collective Trust - Real Estate

36,889

34,753

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Common Collective Trust - Real Estate | Fair Value, Inputs, Level 3 [Member]

13,347

13,583

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

11,143

^[1]

9,719

Hedge Funds

Hedge Funds | Fair Value, Inputs, Level 3 [Member]

25,746

25,034

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

$ 25,746

^[2]

$ 25,034

[1]

[2]

Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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

Defined Benefit Plan, Benefit Obligation

(14,583)

(20,312)

^[2],[3]

377,772

321,400

Medicare Part D Accrued

Plan Participants' Contributions

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

Defined Benefit Plan, Benefit Obligation

41,211

32,960

Plan Participants' Contributions

(1,675)

(1,553)

Medicare Part D Accrued

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

Defined Benefit Plan, Benefit Obligation

^[4]

(3,771)

(3,163)

49,042

45,778

Plan Participants' Contributions

(3,771)

(3,163)

Medicare Part D Accrued

(178)

(99)

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: Changes in Plan Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

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

Retiree contributions

Benefits paid

(14,583)

(20,312)

^[1],[2]

Plan administrative expenses

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

Investment income (loss)

Pension and Other Postretirement Benefit Contributions

Retiree contributions

Benefits paid

Plan administrative expenses

Ending market value of plan assets

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]

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 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: 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: 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: 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 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]

6.35%

7.50%

4.50%

Healthcare trend rate pre-65 | Black Hills Utility Holdings [Member]

2024

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

6.35%

7.50%

4.50%

Healthcare trend rate pre-65 | Cheyenne Light [Member]

2024

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

6.35%

7.50%

4.50%

Healthcare trend rate post-65 | Black Hills Corporation [Member]

2024

2027

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

5.20%

6.25%

4.50%

Healthcare trend rate post-65 | Black Hills Utility Holdings [Member]

2023

2024

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

5.20%

6.25%

4.50%

Healthcare trend rate post-65 | Cheyenne Light [Member]

2023

2024

Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]

5.20%

6.25%

4.50%

Supplemental Employee Retirement Plan [Member]

2023

2024

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%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Rate of Compensation Increase

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]

Supplemental Employee Retirement Plan [Member] | Black Hills Utility Holdings [Member]

3.98%

4.68%

3.88%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Other Postretirement Benefit Plan [Member]

3.30%

3.75%

3.00%

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%

Other Postretirement Benefit Plan [Member] | Black Hills Corporation [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Other Postretirement Benefit Plan [Member] | Black Hills Utility Holdings [Member]

3.70%

4.45%

3.65%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

Other Postretirement Benefit Plan [Member] | Cheyenne Light [Member]

3.65%

4.25%

3.50%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

4.40%

5.15%

4.40%

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%

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%

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]

Pension Plans, Defined Benefit [Member] | Black Hills Utility Holdings [Member]

4.25%

5.10%

4.35%

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]

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: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2015 USD ($)
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 Contingencies (Details) $ in Thousands	12 Months Ended
Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Contractual Obligation, Fiscal Year Maturity [Abstract]
2016	$ 165,484
2017	133,534
2018	82,703
2019	49,196
2020	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. 03, 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: Short-term Purchase Agreement (Details) - Cargill Power Purchase Agreement [Member]	12 Months Ended
	Dec. 31, 2015 MW
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 Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility [Member] - Purchase Option, Property [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Megawatts Capacity Purchased \| MW	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2022
Asset Purchase Option \| $	$ 2.6

Commitments And Contingencies: Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2015 MW
M D U, Montana Dakota Utilities [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	25
City Of Gillette [Member]
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	23
Purchase Power Contract, MEAN, 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 Contingencies: Build Transfer Agreement (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2015

USD ($)

Peak View Wind Project [Member]

$ 159,491

Long-term Purchase Commitment, Amount

109,000

Performance Guarantee [Member] | Electric Utilities [Member] | Peak View Wind Project [Member]

$ 89,718

^[1]

[1]

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

Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Industrial Development Revenue Bonds Due 2027 [Member]

$ 544,756

$ 544,753

^[1]

$ 10,000

10,000

Industrial Development Revenue Bonds Due 2021 [Member]

Mar. 01, 2027

^[1]

$ 7,000

Sep. 01, 2021

[1]	Variable interest rate.

Commitments And Contingencies: Environmental Contingencies (Details) $ in Millions	Dec. 31, 2015 USD ($)
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)
$ in Thousands

12 Months Ended

Dec. 31, 2015

USD ($)

Guarantor Obligations, Term

12/31/2016

Coal Mining [Member] | Surety Bond [Member]

$ 159,491

Guarantor Obligations, Term

Ongoing

Electric Utilities [Member] | Performance Guarantee [Member] | Peak View Wind Project [Member]

$ 69,773

^[1]

89,718

^[2]

Source Gas [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

$ 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]

Oil and Gas Reserves (Unaudited): Oil and Gas Narrative (Details) Mcfe in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) a Gross-Well PUD_Location Mcfe State
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	27.0
Reserves Replaced	209.00%
Proved Undeveloped Reserves, Revisions of Previous Estimates	(10.1)
Proved Undeveloped Reserve Locations \| PUD_Location	(6.000000)
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	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
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)	0.0
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	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Williston Basin [Member] \| Reserves Dropped [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	(21)
Proved Undeveloped Reserves	(1.0)
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 \| $	$ (12.0)
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	(9.0)
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	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
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	0.0
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 \| $	$ (13.0)
Proved Developed Reserves (Energy)	(2.0)
Powder River Basin [Member] \| Prior Year [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	(1)
Proved Undeveloped Reserves	(2.0)
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ (13.0)
Powder River Basin [Member] \| Added Reserves [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations \| PUD_Location	0
Proved Undeveloped Reserves	0.0
Estimated Future Development Costs of Proved Undeveloped Wells \| $	$ 0.0
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Entity Operates \| State	10

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 (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details)

12 Months Ended

Dec. 31, 2015

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2014

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2013

$ / bbl

$ / MMcf

MBbls

MMcf

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]

0.00

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

496

232

Natural Gas [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Balance at Beginning of Year

65,440

63,190

55,985

Additions, Acquisitions (Sales)

(10,058)

(7,156)

(6,984)

^[2]

(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)

8,013

2,966

Natural Gas Liquids [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Balance at Beginning of Year

1,720

Additions, Acquisitions (Sales)

(102)

(135)

Additions, Extensions, Discoveries (bcfe)

232

182

Reserves, Revisions of Previous Estimates

(98)

1,673

Balance at End of Year

1,752

1,720

Proved Developed Reserves (Volume)

1,752

1,530

Proved Undeveloped Reserve (Volume)

191

[1]	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, 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 (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 (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 (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 (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 (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 (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 (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)	$ 40.00	$ 36.81	$ 43.48	$ 47.88	$ 47.11	$ 47.87	$ 55.23	$ 51.09

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

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

Subsequent Event: Financing Activities (Details) - USD ($)
$ in Thousands

12 Months Ended

Jan. 20, 2016

Jan. 13, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 300,000

$ 160,000

$ 800,000

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

1,322,110

$ 997,836

Subsequent Event [Member]

^[1]

$ 250,000

All-in rate

2.29%

Subsequent Event [Member] | Black Hills Corporation [Member]

$ 546,000

Subsequent Event [Member] | Black Hills Corporation [Member] | Senior Unsecured Notes Due 2026 [Member]

550,000

$ 300,000

Fixed interest rate

3.95%

Subsequent Event [Member] | Black Hills Corporation [Member] | Senior Unsecured Notes Due 2019 [Member]

10 years

$ 250,000

Fixed interest rate

2.50%

Subsequent Event [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

3 years

Derivative term

10 years