View Filing Data

407,066

574,989

566,967

Non-regulated energy operations and maintenance

242,367

247,496

251,375

85,830

93,453

71,672

Gain on sale of operating assets

(29,129)

(8,921)

154,632

135,591

126,606

Taxes - property, production and severance

26,868

^[1]

40,487

33,710

27,592

Other operating expenses

2,052

710

980

Total operating expenses

930,173

1,085,949

1,036,271

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

243,711

186,239

183,420

Interest charges -

(117,754)

(116,684)

(105,676)

Allowance for funds used during construction - borrowed

3,462

14,041

10,689

Capitalized interest

682

11,260

4,381

Unrealized gain (loss) on interest rate swaps, net

1,882

(42,010)

(15,193)

Allowance for funds used during construction - equity

1,957

2,017

541

540

932

2,996

Other expense

(71)

(817)

(140)

Other income

2,486

2,490

2,733

Total other income (expense)

(106,816)

(128,771)

(99,669)

Income (loss) from continuning operations before earnings (loss) of unconsoldiated subsidiaries and income taxes

136,895

57,468

83,751

Equity in earnings (loss) of unconsolidated subsidiaries

1,121

1,559

Income tax (expense) benefit

(48,400)

(18,224)

(22,169)

Income (loss) from discontinued operations, net of tax

88,505

40,365

63,141

(6,977)

9,365

5,544

Income (loss) from continuing operations, per share

$ 81,528

$ 49,730

$ 68,685

Earnings (Loss) Per Share, Basic -

$ 2.02

$ 1.01

$ 1.62

Income (loss) from discontinued operations, per share

(0.16)

0.24

0.14

Total Income (loss) per share, Basic

1.86

1.25

1.76

Earnings (Loss) Per Share, Diluted -

Income (loss) from continuing operations, per share

2.01

1.01

1.62

Income (loss) from discontinued operations, per share

(0.16)

0.23

0.14

Total Income (loss) per share, Diluted

$ 1.85

$ 1.24

$ 1.76

Weighted average common shares outstanding:

Basic Shares

43,820

39,864

38,916

Diluted Shares

44,073

40,081

39,091

[1]	Oil and Gas includes a ceiling test impairment (see Note 12).

Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
Statement of Comprehensive Income - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net income (loss) available for common stock	$ 81,528	$ 49,730	$ 68,685
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Benefit plan liability adjustment - net gain (loss) (net of tax of $296, $4,135 and $674, respectively)	(542)	(7,609)	(1,307)
Benefit plan liability adjustments - prior service (costs) (net of tax of $86, $176 and $111, respectively)	(157)	(325)	(214)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $887, $1,708 and $(636), respectively)	(1,268)	(2,831)	1,336
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $534, $(709) and $2,498, respectively)	(643)	1,468	(4,232)
Other comprehensive income (loss), net of tax	(2,610)	(9,297)	(4,417)
Comprehensive income (loss)	78,918	40,433	64,268
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent, Parenthetical Disclosures [Abstract]
Other Comprehensive Income (Loss), Benefit Plans, Net (Gain) Loss, Tax	296	4,135	674
Other Comprehensive Income (Loss), Amortization, Benefit Plans, Prior Service Cost, Tax	86	176	111
Other Comprehensive Income (Loss), Fair Value Adjustment on Derivatives Designated as Cash Flow Hedges, Tax	887	1,708	(636)
Other Comprehensive Income (Loss), Reclassification Adjustment of Cash Flow Hedges Setteled and Included in Net Income, Tax	$ 534	$ (709)	$ 2,498

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 15,462	$ 21,628
Restricted cash and equivalents	7,916	9,254
Accounts receivable, net	163,698	156,774
Materials, supplies and fuel	77,643	84,064
Derivative assets, current	3,236	18,583
Income tax receivable, net	0	9,344
Deferred income tax assets, net, current	77,231	37,202
Regulatory assets, current	31,125	59,955
Other current assets	28,795	21,266
Assets of discontinued operations	0	340,851
Total current assets	405,106	758,921
Investments	16,402	17,261
Property, plant and equipment	3,930,772	3,724,016
Less accumulated depreciation and depletion	(1,188,023)	(934,441)
Total property, plant and equipment, net	2,742,749	2,789,575
Other assets:
Goodwill	353,396	353,396
Intangible assets, net	3,620	3,843
Derivative assets, non-current	510	1,971
Regulatory assets, non-current	188,268	182,175
Other assets, non-current	19,420	19,941
Total other assets, non-current	565,214	561,326
TOTAL ASSETS	3,729,471	4,127,083
Current liabilities:
Accounts payable	84,422	104,748
Accrued liabilities	154,389	151,319
Derivative liabilities, current	96,541	84,367
Accrued income taxes, net	4,936	0
Regulatory liabilities, current	13,628	16,231
Notes payable	277,000	345,000
Current maturities of long-term debt	103,973	2,473
Liabilities of discontinued operations	0	173,929
Total current liabilities	734,889	878,067
Long-term debt, excluding current maturities	938,877	1,280,409
Deferred credits and other liabilities:
Deferred tax liabilities, net, non-current	385,908	300,988
Derivative liabilities, non-current	16,941	49,033
Regulatory liabilities, non-current	127,656	108,217
Benefit plan liabilities	167,397	177,480
Other deferred credits and other liabilities	125,294	123,553
Total deferred credits and other liabilities	823,196	759,271
Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized; issued: 44,278,189 and 43,957,502 shares, respectively	44,278	43,958
Additional paid-in capital	733,095	722,623
Retained earnings	492,869	476,603
Treasury stock at cost - 71,782 and 32,766 shares, respectively	(2,245)	(970)
Accumulated other comprehensive Income (loss)	(35,488)	(32,878)
Total stockholders' equity	1,232,509	1,209,336
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 3,729,471	$ 4,127,083

Consolidated Balance Sheets Balance Sheet Parantheticals - $ / shares	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common Stock, Par or Stated Value Per Share	$ 1.00	$ 1.00	$ 1.00
Common Stock, Shares, Outstanding	44,278,189	43,957,502	39,280,048
Treasury Stock, Shares	71,782	32,766	10,962
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000
Common Stock, Shares, Issued	100,000,000	100,000,000	100,000,000

Consolidated Statements of Cash Flows - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Operating activities:

(Income) loss from discontinued operations, net of tax

$ 81,528

$ 49,730

$ 68,685

6,977

(9,365)

(5,544)

Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:

88,505

40,365

63,141

Deferred financing cost amortization

154,632

135,591

126,606

5,555

5,655

5,859

Derivative fair value adjustments

26,868

^[1]

2,728

(8,693)

13,546

Gain on sale of operating assets

(29,129)

(8,921)

Stock compensation

8,271

5,643

5,637

Unrealized mark-to-market loss (gain) on interest rate swaps

(1,882)

42,010

15,193

Deferred income taxes

39,716

33,600

17,354

Equity in (earnings) loss of unconsolidated subsidiaries

(10)

(1,121)

(1,559)

Allowance for funds used during construction - equity

(540)

(932)

(2,996)

Employee benefit plans

20,973

14,586

16,342

Other adjustments, net

2,751

4,947

(9,710)

Changes in certain operating assets and liabilities:

Materials, supplies and fuel

6,343

(21,385)

(338)

Accounts receivable, unbilled revenues and other current assets

(2,257)

(4,202)

(18,480)

Accounts payable and other current liabilities

(10,713)

(31,091)

(12,848)

12,864

12,691

(21,283)

Contributions to defined benefit pension plans

3,194

11,198

(25,350)

(11,050)

(30,015)

Other operating activities, net

(6,732)

(11,118)

(1,013)

Net cash provided by (used in) operating activities of continuing operations

295,787

216,694

156,565

Net cash provided by (used in) operating activities of discontinued operations

21,184

7,010

(8,813)

Net cash provided by (used in) operating activities

316,971

223,704

147,752

Investing activities:

Property, plant and equipment additions

(349,129)

(440,698)

(472,292)

Payment for acquisition of assets, net of cash acquired

(2,250)

Proceeds from sale of assets

253,791

583

70,357

Other investing activities

(180)

(4,533)

15,407

Net cash provided by (used in) investing activities of continuing operations

(95,518)

(444,648)

(388,778)

Proceeds from sale of business operations

107,511

Net cash provided by (used in) investing activities of discontinued operations

(824)

(2,359)

(390)

Net cash provided by (used in) investing activities

11,169

(447,007)

(389,168)

Financing activities:

Dividends paid on common stock

(65,262)

(59,202)

(56,467)

Common stock issued

4,726

123,041

3,246

Short-term borrowings - issuances

203,753

1,017,300

854,500

Short-term borrowings - repayments

(271,753)

(821,300)

(770,000)

Long-term debt - issuance

200,000

Long-term debt - repayments

(240,077)

(8,382)

(59,926)

Other financing activities

(2,833)

(1,666)

(8,363)

Net cash provided by (used in) financing activities of continuing operations

(371,446)

249,791

162,990

Net cash provided by (used in) financing activities of discontinued operations

(158)

(2,037)

Net cash provided by (used in) financing activities

(371,446)

249,633

160,953

Net change in cash and cash equivalents

(43,306)

26,330

(80,463)

Cash and cash equivalents:

Cash and cash equivalents, beginning of year

^[2]

58,768

32,438

112,901

Cash and cash equivalents, end of year

$ 15,462

58,768

^[2]

32,438

^[2]

Discontinued Operation, Additional Disclosures [Abstract]

Cash and Cash Equivalents of Discontinued Operations

$ 37,100

$ 16,000

[1]	Oil and Gas includes a ceiling test impairment (see Note 12).
[2]	Cash and cash equivalents include cash of discontinued operations of $37.1 million, $16.0 million and $97.5 million at Dec. 31, 2011, 2010 and 2009, respectively.

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, 2009		38,977,526
Stockholders' Equity Attributable to Parent Period Start at Dec. 31, 2009	$ 1,084,837	$ 38,978	$ (224)	$ 591,390	$ 473,857	$ (19,164)
Treasury Stock, Shares, Period Start at Dec. 31, 2009			8,834
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available to common stock	68,685	0	$ 0		68,685
Other comprehensive income (loss), net of tax	(4,417)					(4,417)
Dividends on common stock, shares		0
Dividends on common stock	(56,467)				(56,467)
Share-based compensation, shares		195,915	2,128
Share-based compensation	4,817	$ 196	$ (85)	4,706	0	0
Tax effect of share-based compensation	(33)			(33)	0	0
Equity forward	(288)	$ 0	$ 0	(288)	0	0
Dividend reinvestment and stock purchase plan, shares		106,231	0
Dividend reinvestment an stock purchase plan	3,141	$ 106	$ 0	3,035	0	0
Other stock transactions, shares		(376)	0
Other stock transactions	(5)	$ 0	$ 0	(5)	0	0
Shares, Issued Period End at Dec. 31, 2010		39,280,048
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2010	$ 1,100,270	$ 39,280	$ (309)	598,805	486,075	(23,581)
Treasury Stock, Shares, Period End at Dec. 31, 2010	10,962		10,962
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.44
Net income (loss) available to common stock	$ 49,730				49,730
Other comprehensive income (loss), net of tax	(9,297)	$ 0				(9,297)
Dividends on common stock, shares		0	0
Dividends on common stock	(59,202)	$ 0		0	(59,202)	0
Share-based compensation, shares		161,424	21,804
Share-based compensation	5,076	$ 161	$ (661)	5,576	0	0
Tax effect of share-based compensation	(28)	$ 0	$ 0	(28)	0	0
Issuance of common stock, Shares		4,413,519
Issuance of common stock, Value	119,630	$ 4,414		115,216
Dividend reinvestment and stock purchase plan, shares		102,511	0
Dividend reinvestment an stock purchase plan	3,202	$ 103	$ 0	3,099	0	0
Other stock transactions, shares		0	0
Other stock transactions	(45)	$ 0	$ 0	(45)	0	0
Shares, Issued Period End at Dec. 31, 2011		43,957,502
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2011	$ 1,209,336	$ 43,958	$ (970)	722,623	476,603	(32,878)
Treasury Stock, Shares, Period End at Dec. 31, 2011	32,766		32,766
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.46
Net income (loss) available to common stock	$ 81,528	0			81,528
Other comprehensive income (loss), net of tax	(2,610)	$ 0			0	(2,610)
Dividends on common stock, shares		0
Dividends on common stock	(65,262)				(65,262)
Share-based compensation, shares		219,946	39,016
Share-based compensation	6,040	$ 220	$ (1,275)	7,095	0	0
Tax effect of share-based compensation	117			117	0	0
Dividend reinvestment and stock purchase plan, shares		100,741	0
Dividend reinvestment an stock purchase plan	3,382	$ 100	$ 0	3,282	0	0
Other stock transactions, shares		0	0
Other stock transactions	(22)	$ 0	$ 0	(22)	0	0
Shares, Issued Period End at Dec. 31, 2012		44,278,189
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2012	$ 1,232,509	$ 44,278	$ (2,245)	$ 733,095	$ 492,869	$ (35,488)
Treasury Stock, Shares, Period End at Dec. 31, 2012	71,782		71,782
Dividends, Common Stock [Abstract]
Dividends Paid Per Share	$ 1.48

Business Description and Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business Description, Basis of Presentation and Significant Accounting Policies [Text Block]


	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, Wyo. 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, Wyo. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities located 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 Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 23 for additional information.

For further descriptions of our reportable business segments, see Note 17.

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 17.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 7 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 23 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

The Black Hills Wyoming project financing requires that we maintain cash accounts for various specified purposes. We do not readily have access to these accounts and can only withdraw funds upon meeting certain requirements. Therefore, we have classified these amounts as restricted cash.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable for our Utilities Group primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity.

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

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

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

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



2012	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698



2011	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334
Power Generation	282		—		—			282
Coal Mining	4,056		—		—			4,056
Oil and Gas	11,282		—		(105		)	11,177
Corporate	546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774

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):



	Dec. 31, 2012		Dec. 31, 2011
Materials and supplies	$	43,397	$	40,838
Fuel - Electric Utilities	8,589		8,201
Natural gas in storage held for distribution	25,657		35,025
Total materials, supplies and fuel	$	77,643	$	84,064

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

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, 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. Removal costs associated with non-legal obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

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

Oil and Gas Operations

We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 22 for further discussion.

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

Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at an SEC required rate, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2011 or 2010. See Note 12 for additional information.

The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 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 Nov. 30 each year (or more frequently if impairment indicators arise).

We performed our annual goodwill impairment tests as of Nov. 30, 2012. 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 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 72 percent to Colorado Electric and 28 percent 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 Dec. 31, 2010	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2012	$	250,487	$	94,144	$	8,765	$	353,396

Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based on estimated useful lives. The finite lived intangible assets are currently being amortized over 20 years. Changes to intangible assets for the years ended Dec. 31, were as follows (in thousands):



	2012			2011			2010
Intangible assets, net, beginning balance	$	3,843		$	4,069		$	4,309
Additions (adjustments)	—			—			—
Amortization expense *	(223		)	(226		)	(240		)
Intangible assets, net, ending balance	$	3,620		$	3,843		$	4,069

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of 2013, 2014, 2015, 2016, and 2017.

Asset Retirement Obligations

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

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 10.

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 option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted 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.


•	The commodity basis swaps for the Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which 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 4.

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. 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 loss or gain 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.

Deferred Financing Costs

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

Development Costs

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

Legal Costs

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

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 are not allowed a return. 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 Recovery
	or Settlement Period	As of		As of
	(in years)	Dec. 31, 2012		Dec. 31, 2011
Regulatory assets
Deferred energy and fuel costs adjustments - current^(a)	1	$	16,005	$	33,526
Deferred gas cost adjustments and gas price derivatives^(a)	7	20,741		26,208
AFUDC^(b)	45	12,416		12,482
Employee benefit plans ^(c)	13	115,521		120,708
Environmental^(a)	subject to approval	1,792		1,770
Asset retirement obligations^(a)	44	3,247		3,097
Bond issue cost^(a)	25	3,561		3,704
Renewable energy standard adjustment ^(a)	5	19,484		20,095
Flow through accounting^(d)	35	16,620		12,191
Other regulatory assets^(a)	15	10,006		8,349
		$	219,393	$	242,130

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	21,091	$	16,961
Employee benefit plans^(e)	13	59,362		59,455
Cost of removal^(a)	44	53,526		42,257
Other regulatory liabilities^(f)	25	7,305		5,775
		$	141,284	$	124,448

__________


(a)	Recovery of costs, but 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 of costs, we are allowed a return on approximately $24.6 million.


(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.


(e)	Approximately $13.2 million is included in our rate base calculations as a reduction to rate base.


(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

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 and Gas Price Derivatives - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. In addition, as allowed by state utility commissions, we have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Cheyenne Light files monthly with the WPSC a GCA to be included in tariff rates. 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.

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 itself is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity, and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.

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

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

Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 10 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.

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 in purchased power, transmission and natural gas costs.

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

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

Income Taxes

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

We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax asset will not be realized.

It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property.

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

We account for uncertainty in income taxes recognized in the financial statements in accordance with accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 14 for additional information.

Earnings per Share of Common Stock

Basic earnings per share from continuing and discontinued operations is computed by dividing Income (loss) from continuing or discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings (loss) per share is computed by including all dilutive common shares outstanding during each year.

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



	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income (loss) from continuing operations	$	88,505	$	40,365	$	63,141

Weighted average shares - basic *	43,820		39,864		38,916
Dilutive effect of:
Stock options	13		19		14
Restricted stock	173		153		107
Equity forward instrument	—		—		29
Other dilutive effects	67		45		25
Weighted average shares - diluted	44,073		40,081		39,091

_______________


*	In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

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):



	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options	95	105	158
Restricted stock	53	17	1
Other stock	15	19	1
Anti-dilutive shares excluded from computation of earnings (loss) per share	163	141	160

Discontinued Operations

Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. Additionally, in accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. Assets of discontinued operations and Liabilities of discontinued operations on the accompanying Consolidated Balance Sheets included the assets and liabilities of Enserco Energy Inc. See Note 23 for additional information.

Recently Adopted and Recently Issued Accounting Standards and Legislation	12 Months Ended
	Dec. 31, 2012
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently Adopted and Recently Issued Accounting Standards and Legislation	RECENTLY ISSUED AND ADOPTED ACCOUNTING PRONOUNCEMENTS AND LEGISLATION Recently Adopted Accounting Standards Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update 2011-05 and ASU 2011-12 FASB issued an accounting standards update amending accounting standards for comprehensive income to improve the comparability, consistency and transparency of reporting. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after Dec. 15, 2011, with early adoption permitted. In Dec. 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. Ultimately FASB chose not to reinstate the reclassification adjustment requirements in ASU 2011-05 but instead issued ASU 2013-02 in February 2013. At Dec. 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our consolidated financial statements. See additional Comprehensive Income Statement and additional disclosures in Note 15. Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04 In May 2011, FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a non-financial asset that is different from the asset’s highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after Dec. 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our consolidated financial statements. The additional disclosures are included in Note 4. Extractive Activities — Oil and Gas Reserves, ASU 2010-03 (SEC Release #33-8995) The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, “Modernization of Oil and Gas Reporting,” which amended the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after Dec. 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2010. Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 33-9286, 33-9338, and 34-67717 In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for certain swap transactions we enter into. In addition, many of the transactions which were previously classified as swaps have been converted to exchange-traded futures contracts, which are subject to futures margin posting requirements. The adoption of this rule did not have an impact on our financial position, results of operations or cash flows. In August 2012, the SEC approved a final rule implementing Section 1504 of Dodd-Frank. The rule requires issuers engaged in the commercial development of oil, natural gas or minerals to disclose cash payments made to a foreign government or the Federal government of the United States. We are in the process of evaluating our reporting requirements with the first filing due in 2013. The adoption of this rule will not have an impact on our financial position, results of operations or cash flows. In December 2011, the SEC issued Final Rule 33-9286 providing requirements for Section 1503 of Dodd-Frank. This release requires issuers that are operators of a coal mine to disclose information concerning mine safety violations or other regulatory matters. The required information for our WRDC coal mine is included in Exhibit 95 of this Form 10-K. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required in order to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank. We will continue to evaluate the impact of additional rules as they become available. Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08 In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing on goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after Dec. 15, 2011. The adoption of this standard did not have a material impact on our consolidated financial statements. Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02 In July 2012, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-08. This guidance is effective for interim and annual periods beginning after Sept. 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows. Recently Issued Accounting Pronouncements and Legislation Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, ASU 2013-02 In February 2013, the FASB issued new disclosure requirements for items reclassified out of AOCI to expand the disclosure requirements in ASC 220, Comprehensive Income, for presentation of changes in AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) for items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows. Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11 In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company’s netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning Jan. 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

Risk Management Activities

12 Months Ended

Dec. 31, 2012

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, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and


•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other 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 Dec. 31, 2012, our credit exposure included a $7.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 4.

Oil and Gas Exploration and Production

We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, introduce commodity price risk and variability in our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve cash flows, and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee and the Board of Directors, and are routinely reviewed by the Audit Committee of our Board of Directors.

To mitigate commodity price risk and preserve cash flows, we primarily use over-the-counter swaps, 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 Accumulated other comprehensive income (loss) on the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Consolidated Statements of Income.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:



	Dec. 31, 2012				Dec. 31, 2011
	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)	528,000		8,215,500		528,000			5,406,250
Maximum terms in years ^(b)	1		0.75		1.25			1.75
Derivative assets, current	$	1,405	$	1,831	$	729		$	8,010
Derivative assets, non-current	$	297	$	170	$	771		$	1,148
Derivative liabilities, current	$	847	$	507	$	2,559		$	—
Derivative liabilities, non-current	$	—	$	—	$	811		$	7
Pre-tax accumulated other comprehensive income (loss)	$	206	$	873	$	(1,928	)	$	9,152
Cash collateral included in Derivative liabilities	$	786	$	620	$	—		$	—
Cash collateral included in Other current assets	$	1,078	$	709	$	—		$	—
Expense included in Revenue ^(c)	$	429	$	88	$	(58	)	$	—

________________________


(a)	Crude in Bbls, gas in MMBtu.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.


(c)	Represents the amortization of put premiums.

Based on Dec. 31, 2012 market prices, a $2.1 million gain would be reclassified from AOCI during 2013. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

Our utility customers are exposed to the effect of volatile 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. 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 accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Consolidated Statements of Income 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:



	Dec. 31, 2012		Dec. 31, 2011
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	15,350,000	83	14,310,000	84
Natural gas options purchased	2,430,000	2	1,720,000	3
Natural gas basis swaps purchased	12,020,000	72	7,160,000	60

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:



	Dec. 31, 2012		Dec. 31, 2011
Derivative assets, current	$	—	$	9,844
Derivative assets, non-current	$	43	$	52
Derivative liabilities, non-current	$	—	$	7,156
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	9,596	$	17,556

Cash collateral receivable (payable) included in derivatives	$	8,576	$	19,416
Cash collateral included in Other assets, current	$	4,354	$	—
Option premiums and commissions included in derivatives	$	1,063	$	880

Financing Activities

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:



	Dec. 31, 2012						Dec. 31, 2011
	Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps^(b)			Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps^(b)
Notional	$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.0			1.0			5.0			2.0
Derivative liabilities, current	$	7,039		$	88,148		$	6,513		$	75,295
Derivative liabilities, non-current	$	16,941		$	—		$	20,363		$	20,696
Pre-tax accumulated other comprehensive income (loss)	$	(23,980	)	$	—		$	(26,876	)	$	—
Pre-tax gain (loss)	$	—		$	1,882		$	—		$	(42,010	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	—

___________________


(a)	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.


(b)	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.

Collateral requirements based on our corporate credit rating apply to $50.0 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swap’s negative mark-to-market fair value exceeds $20.0 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or Ba1 or below by Moody’s, we would be required to post collateral for the entire amount of the swap’s negative mark-to-market fair value. We had $6.0 million cash collateral posted at Dec. 31, 2012.

Based on Dec. 31, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 million would be reclassified from AOCI during the next 12 months. Estimated and realized gains or losses will change during future periods as market interest rates change.

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

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Fair Value of Financial Instruments [Abstract]

Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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.

There have been no significant transfers between Level 1 and Level 2 derivative balances during 2012 or 2011. The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	As of Dec. 31, 2012
	Level 1 ^(a)		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Cash equivalents	15,462		—		—		—			15,462
Total	$	15,462	$	3,703	$	43	$	—		$	19,208

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

______________


(a)	Level 1 assets and liabilities are described in Note 5.

The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)

The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.



	As of Dec. 31, 2011
	Level 1 ^(a)		Level 2			Level 3		Cash Collateral and Counterparty Netting		Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	768	$	5	$	773
Basis Swaps -- Oil	—		727			—		—		727
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		9,158			—		—		9,158
Commodity derivatives - Utilities	—		(9,520		)	—		19,416		9,896
Cash equivalents	6,005		—			—		—		6,005
Total	$	6,005	$	365		$	768	$	19,421	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	1,165	$	5	$	1,170
Basis Swaps -- Oil	—		2,200			—		—		2,200
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		7			—		—		7
Commodity derivatives - Utilities	—		7,156			—		—		7,156
Interest rate swaps	—		122,867			—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	133,400

_________


(a)	Level 1 assets and liabilities are described in Note 5.

The following tables present the changes in level 3 recurring fair value (in thousands):



	As of Dec. 31, 2012									As of Dec. 31, 2011
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities			Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	768		$	—		$	768		$	266
Total gain (loss) included in revenue	—			—			—			—
Total gain (loss) included in AOCI	(360		)	(54		)	(414		)	598
Purchases	—			192			192			—
Issuances	—			—			—			—
Settlements	(4		)	—			(4		)	(96		)
Transfers into level 3^(a)	—			—			—			—
Transfers out of level 3^(b)(c)	(404		)	(95		)	(499		)	—
Balances at end of period	$	—		$	43		$	43		$	768

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)	$	(54	)	$	(101	)



	As of Dec. 31, 2012								As of Dec. 31, 2011
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities		Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	1,165		$	—	$	1,165		$	—
Total gain (loss) included in revenue	—			—		—			—
Total gain (loss) included in AOCI	182			—		182			1,165
Purchases	—					—			—
Issuances	—			—		—			—
Settlements	—			—		—			—
Transfers into level 3^(a)	—			—		—			—
Transfers out of level 3^(b)(c)	(1,347		)	—		(1,347		)	—
Balances at end of period	$	—		$	—	$	—		$	1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	—		$	—

__________


(a)	Transfers into Level 3 would 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.


(b)	Transfers out of Level 3 would 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.


(c)	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

Fair Value Measures

As required by accounting standards for derivatives and hedging, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements. Further, the amounts do not include net cash collateral on deposit in margin accounts at Dec. 31, 2012 and 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross 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 3.

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31. exclusive of cash collateral (in thousands):



		2012				2011
	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	$	2,874	$	—	$	8,739	$	—
Commodity derivatives	Derivative assets - non-current	510		—		1,919		—
Commodity derivatives	Derivative liabilities - current	—		1,993		—		2,559
Commodity derivatives	Derivative liabilities - non-current	—		821		—		818
Interest rate swaps	Derivative liabilities - current	—		7,038		—		6,513
Interest rate swaps	Derivative liabilities - non-current	—		16,941		—		20,363
Total derivatives designated as hedges		$	3,384	$	26,793	$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	362	$	—	$	—	$	9,572
Commodity derivatives	Derivative assets - non-current	—		—		—		(52		)
Commodity derivatives	Derivative liabilities - current	1,180		4,957		—		—
Commodity derivatives	Derivative liabilities - non-current	406		5,153		—		7,156
Interest rate swaps	Derivative liabilities - current	—		94,108		—		75,295
Interest rate swaps	Derivative liabilities - non-current	—		—		—		20,696
Total derivatives not designated as hedges		$	1,948	$	104,218	$	—	$	112,667

A description of our derivative activities is discussed in Note 3. The following tables present the impact that derivatives had on our Consolidated Statements of Income.

Cash Flow Hedges

The impact of cash flow hedges on our Consolidated Statements of Income and Balance Sheets for the years ended are presented as follows (in thousands):



	Dec. 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—



	Dec. 31, 2011
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(12,280	)	Interest expense	$	(7,664	)		$	—
Commodity derivatives	7,741			Revenue	5,487				—
Total	$	(4,539	)		$	(2,177	)		$	—



	Dec. 31, 2010
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(13,527	)	Interest expense	$	(7,609	)		$	—
Commodity derivatives	15,456			Revenue	14,339				—
Total	$	1,929			$	6,730			$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Consolidated Statements of Income for the years ended Dec. 31 was as follows (in thousands):



		2012			2011			2010
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	Unrealized gain (loss) on interest rate swap, net	$	1,882		$	(42,010	)	$	(15,193	)
Interest rate swaps - realized	Interest expense	(12,959		)	(13,373		)	(13,312		)
		$	(11,077	)	$	(55,383	)	$	(28,505	)

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2012

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	15,462	$	15,462	$	21,628	$	21,628
Restricted cash and equivalents ^(a)	$	7,916	$	7,916	$	9,254	$	9,254
Notes payable ^(a)	$	277,000	$	277,000	$	345,000	$	345,000
Long-term debt, including current maturities ^(b)	$	1,042,850	$	1,231,559	$	1,282,882	$	1,464,289

_______________


(a)	Fair value approximates carrying 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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-Term Debt

For additional information on our long-term debt, see Note 8.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
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Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment Disclosure [Text Block]

PROPERTY, PLANT AND EQUIPMENT

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



Utilities Group	2012			2011			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	$	959,636	45	$	707,498	49	25	80
Electric transmission	234,279		50	170,146		49	40	65
Electric distribution	631,654		44	580,699		45	15	65
Plant acquisition adjustment	4,870		32	4,870		32	32	32
General	137,584		22	136,304		22	3	60
Capital lease - plant in service ^(a)	260,874		19	260,874		20	19	19
Construction work in progress	48,008			288,760
Total electric plant	2,276,905			2,149,151
Less accumulated depreciation and amortization	439,772			385,840
Electric plant net of accumulated depreciation and amortization	$	1,837,133		$	1,763,311

_____________


(a)	Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP.



	2012			2011			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13	37	$	35	37	37	37
Gas transmission	18,071		54	15,543		53	53	57
Gas distribution	474,998		46	442,114		46	41	56
General	68,856		19	56,869		19	16	22
Construction work in progress	6,305			8,813
Total gas plant	568,243			523,374
Less accumulated depreciation and amortization	68,530			52,249
Gas plant net of accumulated depreciation and amortization	$	499,713		$	471,125



2012									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	139,396	$	1,323	$	38,541	$	102,178	35	2	40
Coal Mining	148,045		7,023		80,210		74,858		14	2	59
Oil and Gas	785,594		—		562,926		222,668		24	3	25
	$	1,073,035	$	8,346	$	681,677	$	399,704



2011									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	135,051	$	930	$	35,074	$	100,907	36	2	40
Coal Mining	140,683		4,341		73,777		71,247		20	2	39
Oil and Gas	763,645		—		386,377		377,268		25	3	26
	$	1,039,379	$	5,271	$	495,228	$	549,422



2012										Lives ( in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	368	$	3,875	$	(1,956	)	$	6,199	6	2	30

___________

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



2011									Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	2,136	$	4,705	$	1,124	$	5,717	6	2	30

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

Jointly Owned Facilities [Text Block]

Jointly Owned Facilities

12 Months Ended

Dec. 31, 2012

Jointly Owned Facilities [Abstract]

JOINTLY OWNED FACILITIES

Oil and Gas

BHEP owns a 44.7 percent non-operating interest in a natural gas processing facility (the Newcastle Gas Plant). The Newcastle Gas Plant gathers and processes gas, primarily from the Finn-Shurley Field in Wyoming. We receive our proportionate share of the Newcastle Gas Plant’s net revenues and are committed to pay our proportionate share of additions, replacements and operating and maintenance expenses. Each of the respective owners is responsible for providing its own financing. As of Dec. 31, 2012, our investment in the Newcastle Gas Plant included $4.4 million in plant and equipment which is included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. This asset is included in the asset pool being depleted and therefore accumulated depreciation is not separated by asset. Our share of direct expenses is included in the corresponding categories of revenue and expenses in the accompanying Consolidated Statements of Income.

Utility Plant

•

Black Hills Power owns a 20 percent 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 percent 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 megawatts - 200 megawatts West to East and 200 megawatts 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 percent 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 percent of the Busch Ranch Wind Project while AltaGas owns the remaining undivided ownership interest. We retain responsibility for operations of the wind farm.

Non-Regulated Plants


•	Black Hills Wyoming owns 76.5 percent of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for their 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.

Our share of direct expenses for the jointly-owned utility and non-regulated facilities is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. Each of the respective owners is responsible for providing its own financing.

At Dec. 31, 2012, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,465	$	451	$	47,776
Transmission Tie	$	19,648	$	—	$	4,414
Wygen I	$	105,020	$	343	$	25,162
Wygen III	$	130,267	$	565	$	8,376
Busch Ranch Wind Project	$	17,984	$	—	$	150

Long-Term Debt

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

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



	Due Date	Interest Rate	Dec. 31, 2012			Dec. 31, 2011
Corporate
Senior unsecured notes due 2013 ^{(a) (c)}	May 15, 2013	6.50%	$	—		$	225,000
Unamortized discount on notes due 2013			—			(41		)
Senior unsecured notes due 2014^(c)	May 15, 2014	9.00%	250,000			250,000
Senior unsecured notes due 2020 ^(c)	July 15, 2020	5.88%	200,000			200,000
Corporate term loan, variable rate ^(b)	Sept. 30, 2013	1.63%	100,000			100,000
Total Corporate Debt			550,000			774,959

Electric Utilities
First Mortgage Bonds due 2032	Aug. 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	Nov. 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(111		)	(115		)
Pollution control revenue bonds due 2014 ^(d)	Oct. 1, 2014	4.80%	—			6,450
Pollution control revenue bonds due 2024	Oct. 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	Nov. 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(b)	Sept. 1, 2021	0.20%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(b)	March 1, 2027	0.20%	10,000			10,000
Series 94A Debt, variable rate ^(b)	June 1, 2024	1.35%	2,855			2,855
Other long-term debt	May 25, 2012	13.66%	—			72
Total Electric Utilities			396,944			403,462

Power Generation
Black Hills Wyoming project financing, variable rate ^(b)	Dec. 9, 2016	3.59%	95,906			104,461

Total long-term debt			1,042,850			1,282,882
Less current maturities			103,973			2,473
Net long-term debt			$	938,877		$	1,280,409

_______________


(a)	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.


(b)	Variable interest rates; rates presented are as of Dec. 31, 2012.


(c)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.


(d)	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.

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



2013	$	103,973
2014	$	256,023
2015	$	6,963
2016	$	78,947
2017	$	—
Thereafter	$	597,055

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at Dec. 31, 2012.

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 either currently not callable or are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds.

Early Redemption of Long-term Debt

On Oct. 31, 2012, we redeemed $225.0 million of senior unsecured 6.5 percent notes, which were originally scheduled to mature on May 15, 2013 for $238.8 million. The payment included accrued interest and a make-whole provision of $7.1 million included in Interest expense on the accompanying Consolidated Statements of Income.

On May 15, 2012, Black Hills Power repaid its 4.8 percent Pollution Control Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on Oct. 1, 2014.

Loan Extensions

Our $100.0 million term loan (the “Loan”) with J.P. Morgan and Union Bank was extended through Sept. 30, 2013. The cost of borrowings under the Loan was based on a spread of 1.375 percent over LIBOR (1.63 percent at Dec. 31, 2012). The covenants 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 were as follows (in thousands):



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Senior unsecured notes due 2014	$	634	$	462	$	462	$	462
Senior unsecured notes due 2020	$	1,260	$	167	$	167	$	77
First mortgage bonds due 2032	$	651	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,037	$	76	$	76	$	76
First mortgage bonds due 2037	$	766	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	3,177	$	1,037	$	1,012	$	1,036
Other	$	721	$	57	$	70	$	74

Notes Payable

12 Months Ended

Dec. 31, 2012

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of Dec. 31, 2012, we were in compliance with all of these covenants.

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



	Dec. 31, 2012				Dec. 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	127,000	$	36,300	$	195,000	$	43,700
Term Loan due June 2013^(a)	150,000		—		150,000		—
Total	$	277,000	$	36,300	$	345,000	$	43,700

__________


(a)	In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50 percent, 1.50 percent and 1.50 percent, respectively, at Dec. 31, 2012. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25 percent.

Deferred financing costs on the new facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and included in Interest expense on the accompanying Consolidated Statements of Income. Upon entering into the Revolving Credit Facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense. The deferred financing costs on the new facility are being amortized as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Revolving Credit Facility	$	2,068	$	2,187	$	1,891	$	1,340

Corporate Term Loans

In June 2012, we extended our one-year $150.0 million unsecured, single draw term loan until June 24, 2013. The cost of borrowing under the extended loan is based on a spread of 1.10 percent over LIBOR (1.35 percent at Dec. 31, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of Dec. 31, 2012.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):



	At Dec. 31, 2012			Covenant Requirement
Consolidated net worth	$	1,232,509		Greater than	$	924,895
Recourse leverage ratio	53.8		%	Less than	65.0		%

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

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 at 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 Gas Utilities segment. 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):



	Dec. 31, 2011		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)		Dec. 31, 2012
Electric Utilities	$	3,064	$	3,626	$	—		$	291	$	—	$	6,981
Gas Utilities	270		—		(22		)	11		—		259
Coal Mining	17,158		1,627		—			921		580		20,286
Oil and Gas	22,422		158		(1,059		)	1,345		156		23,022
Total	$	42,914	$	5,411	$	(1,081	)	$	2,568	$	736	$	50,548



	Dec. 31, 2010		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)			Dec. 31, 2011
Electric Utilities	$	3,039	$	—	$	—		$	25	$	—		$	3,064
Gas Utilities	255		—		—			15		—			270
Coal Mining	17,560		—		—			1,123		(1,525		)	17,158
Oil and Gas	21,663		43		(627		)	1,343		—			22,422
Total	$	42,517	$	43	$	(627	)	$	2,506	$	(1,525	)	$	42,914

_____________________


(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

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.

Common Stock

12 Months Ended

Dec. 31, 2012

Common Stock, Including Additional Paid in Capital, Net of Discount [Abstract]

Common Stock

COMMON STOCK

Equity Issuance

On Nov. 10, 2010, we entered into an Equity Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Subsequently, the underwriters exercised the over-allotment option to purchase 413,519 additional shares under the same terms as the original Forward Equity Agreement. We settled the equity forward instrument on Nov. 1, 2011 by physically delivering 4,413,519 shares of common stock in return for proceeds of $119.6 million.

Equity Compensation Plans

Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 863,929 shares available to grant at Dec. 31, 2012.

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 Dec. 31, 2012, total unrecognized compensation expense related to non-vested stock awards was $7.8 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follow (in thousands):



	2012		2011		2010
Stock-based compensation expense	$	8,271	$	5,643	$	5,637

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 Dec. 31, 2012 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	264		$	30.50
Granted	—		—
Forfeited/canceled	(16	)	32.04
Expired	(26	)	34.97
Exercised	(101	)	28.21
Balance at end of period	121		$	31.23	5.7	$	619

Exercisable at end of period	71		$	30.65	3.8	$	404

The table below provides details of our option plans at Dec. 31 (in thousands):



	2012		2011		2010
Summary of Stock Options
Unrecognized compensation expense	$	218	$	479	$	—
Intrinsic value of options exercised^(a)	$	623	$	94	$	234
Net cash received from exercise of options	$	2,839	$	1,009	$	1,034
Tax benefit realized from exercise of shares ^(b)	$	218	$	33	$	82

_____________________


(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, 2012, the unrecognized compensation expense related to non-vested stock options is expected to be recognized over a weighted-average period of 1.4 years.

Restricted Stock and Restricted Stock Units

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 non-vested restricted stock units at Dec. 31, 2012 was as follows:



	Restricted Stock and Stock Units		Weighted-Average Grant Date Fair Value
	(in thousands)
Restricted Stock and Restricted Stock Units balance at beginning of period	278		$	28.82
Granted	151		34.99
Vested	(108	)	27.94
Forfeited	(34	)	30.22
Restricted Stock and Restricted Stock Units balance at end of period	287		$	32.23

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



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2012	$	34.99	$	3,781
2011	$	30.33	$	3,211
2010	$	27.30	$	2,212

As of Dec. 31, 2012, there was $5.2 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.0 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 percent in cash and 50 percent 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 percent in cash. If it is determined that a change-in-control is probable, the equity portion of $1.7 million at Dec. 31, 2012 would be reclassified as a liability.

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



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
Jan. 1, 2010	Jan. 1, 2010 - Dec. 31, 2012	66	0%	175%
Jan. 1, 2011	Jan. 1, 2011 - Dec. 31, 2013	62	0%	175%
Jan. 1, 2012	Jan. 1, 2012 - Dec. 31, 2014	65	0%	200%

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



	Equity Portion				Liability Portion
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average Dec. 31, 2012 Fair Value
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	106		$	26.47	106
Granted	33		32.26		33
Forfeited	(7	)	26.19		(7	)
Vested	(36	)	29.20		(36	)
Performance Shares balance at end of period	96		$	27.49	96		$	26.04

The grant date fair values for the performance shares granted in 2012, 2011 and 2010 were determined by Monte Carlo simulation using a blended volatility of 21 percent, 30 percent and 31 percent, respectively, comprised of 50 percent historical volatility and 50 percent 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
Dec. 31, 2012	$	32.26
Dec. 31, 2011	$	25.92
Dec. 31, 2010	$	24.26

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



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
Jan. 1, 2009 to Dec. 31, 2011	2012	—	$	—	$	—
Jan. 1, 2008 to Dec. 31, 2010	2011	—	$	—	$	—
Jan. 1, 2007 to Dec. 31, 2009	2010	—	$	—	$	—

On Jan. 30, 2013, the Compensation Committee of our Board of Directors determined that the company’s total shareholder return for the Jan. 1, 2010 through Dec. 31, 2012 performance period was at the 78^th percentile of its peer group and confirmed a payout equal to 170.75 percent of target shares, valued at $4.5 million. The payout was fully accrued at Dec. 31, 2012.

As of Dec. 31, 2012, there was $2.4 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.

Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent 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 Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31, is as follows (shares in thousands):



	2012		2011
Shares Issued	101		103

Weighted Average Price	$	33.58	$	31.23

Unissued Shares Available	353		453

Dividend Restrictions

Our credit facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of Dec. 31, 2012, 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 Dec. 31, 2012:


•	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 Dec. 31, 2012, the restricted net assets at our Utilities Group were approximately $263.1 million.


•	As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted shareholders’ equity of at least $100.0 million.

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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Reference 20: http://www.xbrl.org/2003/role/presentationRef
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Leases of Lessee Disclosure [Text Block]

Impairment of Long-Lived Assets	12 Months Ended
Impairment of Long-Lived Assets	Dec. 31, 2012
Asset Impairment Charges [Abstract]
Asset Impairment Charges [Text Block]	IMPAIRMENT OF LONG-LIVED ASSETS Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and acquisition of crude oil and natural gas reserves, all costs attributable to these activities are capitalized. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. Any costs in excess of the ceiling are written off as a non-cash charge. As a result of continued low commodity prices in the second quarter of 2012, we recorded a $26.9 million non-cash impairment of oil and gas assets included in the Oil and Gas segment. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead; for crude oil, the average NYMEX price was $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead.

Operating Leases

12 Months Ended

Dec. 31, 2012

Leases, Operating [Abstract]

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 Dec. 31 was as follows (in thousands):



	2012		2011		2010
Rent expense	$	6,839	$	6,125	$	4,219

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



2013	$	2,690
2014	$	2,377
2015	$	2,144
2016	$	1,465
2017	$	1,269
Thereafter	$	2,811

The entire disclosure for lessee entity's leasing arrangements including, but not limited to, all of the following: (a.) The basis on which contingent rental payments are determined, (b.) The existence and terms of renewal or purchase options and escalation clauses, (c.) Restrictions imposed by lease agreements, such as those concerning dividends, additional debt, and further leasing.

Income Tax Disclosure [Text Block]

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

INCOME TAXES

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



	2012			2011			2010
Current:
Current federal income tax expense (benefit)	$	4,972		$	(14,539	)	$	678
Current state income tax expense (benefit)	3,712			(837		)	4,137
	8,684			(15,376		)	4,815
Deferred:
Deferred federal income tax expense (benefit)	39,876			30,876			20,186
Deferred state income tax expense (benefit)	68			2,970			(2,495		)
Tax credit amortization expense (benefit)	(228		)	(246		)	(337		)
	39,716			33,600			17,354

Total income tax expense (benefit)	$	48,400		$	18,224		$	22,169

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



	2012			2011
Deferred tax assets:
Asset valuation reserves	$	3,101		$	2,605
Regulatory liabilities	57,471			40,642
Employee benefits	23,767			22,488
Items of other comprehensive income (loss)	20,038			36,398
Derivative fair value adjustments	35,947			39,099
State net operating loss	8,300			12,311
Federal net operating loss	147,153			195,834
Asset impairment	55,971			47,033
State tax credits	15,546			—
Other deferred tax assets	25,101			17,683
Less: Valuation allowance	(6,192		)	(773		)
Total deferred tax assets	386,203			413,320

Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(571,262		)	(508,261		)
Regulatory assets	(23,537		)	(23,498		)
Mining development and oil exploration	(48,411		)	(94,334		)
Deferred costs	(17,723		)	(15,663		)
State deferred tax liability	(19,986		)	(14,611		)
Other deferred tax liabilities	(13,961		)	(20,739		)
Total deferred tax liabilities	(694,880		)	(677,106		)

Net deferred tax liability	$	(308,677	)	$	(263,786	)

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



	2012		2011		2010
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	2.0		1.8		1.1
Amortization of excess deferred and investment tax credits	(0.2	)	(0.5	)	(0.4	)
Percentage depletion in excess of cost	(1.3	)	(2.5	)	(1.7	)
Equity AFUDC	—		(0.5	)	(1.0	)
Tax credits	—		—		(3.2	)
Accounting for uncertain tax positions adjustment	0.8		2.8		1.2
Flow-through adjustments^(a)	(1.3	)	(4.5	)	(4.6	)
Other tax differences	0.4		(0.5	)	(0.4	)
	35.4	%	31.1	%	26.0	%

_________________________

(a)

The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will 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 we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit in 2010 that was attributable to the 2008 through 2010 tax years. We continue to record a tax benefit consistent with the flow through method in accordance with such regulatory treatment.

At Dec. 31, 2012, we had federal and state NOL carryforwards of $425.8 million and $475.6 million, respectively, which will expire at various dates as follows (in thousands):



Expiration Years	Federal Net Operating Loss Carry forward		State Net Operating Loss Carry forward
2014-2019	$	2,217	$	146,854
2020-2025	$	16,461	$	119,459
2026-2031	$	407,086	$	209,319

As of Dec. 31, 2012, we had a $2.2 million valuation allowance against the state NOL carryforwards. The re-evaluation of our ability to utilize such NOLs resulted in an increase of the valuation allowance of approximately $1.4 million and an increase to tax expense. The valuation allowance adjustment was primarily attributable to an increase in the NOL generated, as trued up with the filing of the 2011 tax return, in certain states whose carryforward period is much shorter than what is allowed for federal income tax purposes. 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 Jan. 1, 2010	$	107,088
Additions for prior year tax positions	19,592
Reductions for prior year tax positions	(76,545		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2010	50,135
Additions for prior year tax positions	2,725
Reductions for prior year tax positions	(3,533		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2011	49,327
Additions for prior year tax positions	111
Reductions for prior year tax positions	(8,906		)
Additions for current year tax positions	151
Settlements	—
Ending balance at Dec. 31, 2012	$	40,683

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.5 million.

We recognized the following interest expense for the years ended Dec. 31 as follows (in thousands):



	2012		2011		2010
Interest expense included in income tax expense	$	1,400	$	1,400	$	2,300

We had approximately $8.3 million pre-tax and $6.9 million pre-tax of accrued interest associated with income taxes at December 31, 2012 and 2011, respectively.

We file income tax returns with the IRS, various state jurisdictions and Canada. We are currently under examination by the IRS for the 2007, 2008 and 2009 tax years and by the state of Colorado for tax years 2001 through 2009. We remain subject to examination by Canadian income tax authorities for tax years as early as 1999.

We have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125.0 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS has challenged our position with respect to the like-kind exchange and it is reasonably possible that the total unrecognized tax benefits attributable to such transaction could change significantly due to a settlement with the IRS prior to Dec. 31, 2013. However, based on the information currently available, it is difficult to determine any reasonable estimate of the financial statement impact including the impact on the effective tax rate.

Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At Dec. 31, 2012, we had remaining foreign tax credit carryforwards of approximately $2.3 million, which break down as follows (in thousands):



Foreign Tax Credit Carryforward, Gross		Expiration Year
$	263	2012
$	6	2013
$	376	2014
$	693	2015
$	5	2016
$	41	2017
$	961	2018

As of Dec. 31, 2012, we had a $0.5 million valuation allowance against the foreign tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in the establishment of a valuation allowance and an increase to tax expense. Utilization of the foreign tax credit carryforward balance is expected to be included as computational adjustments upon finalization of our current IRS examination covering tax years 2007 to 2009. Due to the expectation that the IRS examination will come to a conclusion within the next twelve months, the balance was reclassified to current tax assets and netted against current tax liability. In addition, approximately $1.8 million of foreign tax credit carryforward is 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 of such carryforward.

State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2012, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
Investment tax credit	$	14,711	2023
Research and development	$	835	No expiration

As of Dec. 31, 2012, we had a $3.4 million valuation allowance against the state tax credit carryforwards. 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.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Comprehensive Income

12 Months Ended

Dec. 31, 2012

Comprehensive Income (Loss)

ACCUMULATED OTHER COMPREHENSIVE INCOME

Balances by classification included within Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(1,911		)	(699		)	(2,610		)
As of Dec. 31, 2012	$	(15,713	)	$	(19,775	)	$	(35,488	)


	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2010 *	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,363		)	(7,934		)	(9,297		)
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)

____________

* Includes cash flow hedges of equity method investee related to the Idaho Cogeneration Facilities.

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
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
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Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2012

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



Years ended Dec. 31,	2012			2011			2010
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	35,556		$	37,529		$	48,879
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	5,743		$	(1,525	)	$	(1,858	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(116,593	)	$	(103,110	)	$	(101,947	)
Income taxes, net	$	(3,027	)	$	9,854		$	9,384

Business Segments

12 Months Ended

Dec. 31, 2012

Segment Reporting Information, Additional Information [Abstract]

Summary of Information Relating to Segments of our Business

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. All of our operations and assets are located within the United States.

On Feb. 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 classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 23.

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of Dec. 31,	2012		2011
Utilities:
Electric ^(a)	$	2,387,458	$	2,254,914
Gas	765,165		746,444
Non-regulated Energy:
Power Generation^(a)	119,170		129,121
Coal Mining	83,810		88,704
Oil and Gas	258,460		425,970
Corporate^(b)	115,408		141,079
Discontinued Operations^(c)	—		340,851
Total assets	$	3,729,471	$	4,127,083

__________________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.


(b)	Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.


(c)	See Note 23 for further information relating to discontinued operations.



Capital Expenditures and Asset Acquisitions^(a) for the years ended Dec. 31,	2012		2011
Utilities:
Electric Utilities	$	167,263	$	173,078
Gas Utilities	45,711		43,954
Non-regulated Energy:
Power Generation	5,547		98,927
Coal Mining	13,420		10,438
Oil and Gas	107,839		89,672
Corporate	7,376		13,279
Total capital expenditures and asset acquisitions of continuing operations	347,156		429,348
Total capital expenditures of discontinued operations	824		2,359
Total capital expenditures and asset acquisitions	$	347,980	$	431,707

_________________


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



Property, Plant and Equipment as of Dec. 31,	2012		2011
Utilities:
Electric Utilities ^(a)	$	2,276,905	$	2,149,151
Gas Utilities	568,243		523,374
Non-regulated Energy:
Power Generation ^(a)	140,719		135,981
Coal Mining	155,068		145,024
Oil and Gas	785,594		763,645
Corporate	4,243		6,841
Total property, plant and equipment	$	3,930,772	$	3,724,016

_______________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.



	Consolidating Income Statement
Year ended Dec. 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Fuel, purchased power and cost of gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Gross margin	353,492			208,732			79,389			57,778			79,072			196,453			(208,098		)	766,818

Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets ^(a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets^(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711

Interest expense ^(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505

________________


(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22).


(b)	Oil and Gas includes a ceiling test impairment (see Note 12).


(c)	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8).



	Consolidating Income Statement
Year ended Dec. 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Inter-company revenue	13,396			—			27,613			34,090			—			192,250			(267,349		)	—
Fuel, purchased power and cost of gas sold	310,352			331,961			—			—			—			97			(67,421		)	574,989
Gross margin	303,979			222,623			31,672			66,892			79,808			192,153			(199,928		)	697,199

Operations and maintenance	142,815			121,980			16,538			56,617			41,380			170,947			(174,908		)	375,369
Gain on sale of operating assets ^(a)	(768		)	—			—			—			—			1			767			—
Depreciation, depletion and amortization	52,475			24,307			4,199			18,670			35,690			11,205			(10,955		)	135,591
Operating income (loss)	109,457			76,336			10,935			(8,395		)	2,738			10,000			(14,832		)	186,239

Interest expense	(53,770		)	(31,621		)	(8,903		)	(9		)	(5,896		)	(93,314		)	102,130			(91,383		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(42,010		)	—			(42,010		)
Interest income	14,794			5,645			1,529			3,897			2			64,299			(88,149		)	2,017
Other income (expense), net	481			217			1,094			2,192			(216		)	46,510			(46,552		)	3,726
Income tax benefit (expense)	(23,271		)	(16,408		)	(1,644		)	1,891			1,651			19,289			268			(18,224		)
Income (loss) from continuing operations	$	47,691		$	34,169		$	3,011		$	(424	)	$	(1,721	)	$	4,774		$	(47,135	)	$	40,365

_________________


(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.



	Consolidating Income Statement
Year ended Dec. 31, 2010	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	554,617		$	550,707		$	4,297		$	31,285		$	74,164		$	—		$	—		$	1,215,070
Inter-company revenue	15,397			—			26,052			26,557			—			140,756			(204,141		)	4,621
Fuel, purchased power and cost of gas sold	292,811			333,717			—			—			—			150			(59,711		)	566,967
Gross margin	277,203			216,990			30,349			57,842			74,164			140,606			(144,430		)	652,724

Operations and maintenance	136,873			125,447			16,210			34,028			39,299			129,641			(129,879		)	351,619
Gain on sale of operating assets ^(a)	(6,238		)	(2,683		)	—			—			—			—			—			(8,921		)
Depreciation, depletion and amortization	47,276			25,258			4,466			19,083			30,283			9,469			(9,229		)	126,606
Operating income (loss)	99,292			68,968			9,673			4,731			4,582			1,496			(5,322		)	183,420

Interest expense	(43,855		)	(28,927		)	(9,303		)	(177		)	(5,380		)	(75,406		)	72,442			(90,606		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(15,193		)	—			(15,193		)
Interest income	6,812			1,472			1,193			3,357			8			54,472			(66,773		)	541
Other income (expense), net	3,215			47			854			2,149			722			28,768			(28,607		)	7,148
Income tax benefit (expense)	(18,012		)	(14,449		)	(266		)	(2,379		)	425			12,512			—			(22,169		)
Income (loss) from continuing operations	$	47,452		$	27,111		$	2,151		$	7,681		$	357		$	6,649		$	(28,260	)	$	63,141

______________________


(a)	Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22).

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

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

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 percent 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 percent per year with 100 percent vesting when the participant has 5 years of service with the Company.

Funded Status of Benefit Plans

The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, these costs are recoverable in our rates, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax (see Note 1). The measurement date for all plans is Dec. 31. As of Dec. 31, 2012, the funded status of our Defined Benefit Pension Plans was $(94.4) million; the funded status of our Supplemental Non-qualified Defined Benefit Plans was $(34.4) million; and the funded status of our Non-pension Defined Benefit Postretirement Healthcare Plans was $(42.3) million.

Defined Benefit Pension Plans (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 year of service and calculations of average earnings during a specific time period prior to retirement. As of Jan. 1, 2012, both Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Pension Plans were frozen.

In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of Jan. 1, 2012. Additionally, effective Oct. 1, 2012, the Cheyenne Light Pension Plan was merged into the BHC Pension Plan. The Pension Plan benefits are based on years of service and compensation levels.

On Oct. 29, 2012, our Board of Directors approved a new 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 structured portfolio strategy that will provide liquidity to meet the Plans’ benefit payment obligations. The Pension Plans’ assets are held in trust and consist primarily of equity and fixed income investments. The expected long-term rate of return for investments was 7.25 percent and 8.75 percent for the 2012 and 2011 plan years, respectively. Our Pension Plan funding policy is in accordance 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 Dec. 31 were as follows:



	2012		2011
Equity	47	%	64	%
Real estate	8		3
Fixed income	44		32
Cash	1		1
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. We may amend or change the Healthcare Plans periodically. A portion of the Healthcare Plans is pre-funded via VEBAs. We have determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

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 Dec. 31 were as follows (in thousands):



	2012		2011
Defined Contribution Plan
Company Retirement Contribution	$	2,639	$	2,440
Matching contributions - Defined Contribution Plans	$	8,981	$	8,916



	2012		2011
Defined Benefit Plans
Defined Benefit Pension Plans	$	25,350	$	11,050
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	5,191	$	4,963
Supplemental Non-Qualified Defined Benefit Plans	$	1,270	$	956

While we do not have required contributions, we expect to make approximately $8.8 million in contributions to our Pension Plans in 2013.

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	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	1,486	$	—	$	—	$	1,486
Common Collective Trust - Money Market	—		1,118		—		1,118
Common Collective Trust - Equity	—		126,105		—		126,105
Common Collective Trust - Fixed Income	—		114,440		—		114,440
Common Collective Trust - Real Estate	—		13,361		7,770		21,131
Structured Products	—		4,536		—		4,536
Insurance Contracts	—		—		—		—
Total investments measured at fair value	$	1,486	$	259,560	$	7,770	$	268,816



Defined Benefit Pension Plans	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	70	$	—	$	—	$	70
Registered Investment Companies - Equity	23,498		—		—		23,498
Registered Investment Companies - Fixed Income	23,422		—		—		23,422
103-12 Investment Entities - Equity	—		10,329		—		10,329
Common Collective Trust - Money Market	—		25		—		25
Common Collective Trust - Equity	—		103,004		—		103,004
Common Collective Trust - Fixed Income	—		48,024		—		48,024
Common Collective Trust - Real Estate	—		—		7,042		7,042
Structured Products	—		3,884		—		3,884
Insurance Contracts	—		2,424		—		2,424
Total investments measured at fair value	$	46,990	$	167,690	$	7,042	$	221,722



Non-pension Defined Benefit Postretirement Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,351	$	—	$	4,351
Total investments measured at fair value	$	—	$	4,351	$	—	$	4,351



Non-pension Defined Benefit Postretirement Plan	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,319	$	—	$	4,319
Total investments measured at fair value	$	—	$	4,319	$	—	$	4,319

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 Dec. 31 (in thousands):



	2012		2011
Balance, beginning of period	$	7,043	$	6,126
Unrealized gain (loss)	727		917
Balance, end of period	$	7,770	$	7,043

The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	7,770	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.

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

Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded.

103-12 Investment Entities: The trustee determines the value of the pooled trust fund and the units thereof in U.S. Dollars as of (i) each daily valuation date, and (ii) each other day designated by mutual agreement between the trustee and the investment manager. As of each valuation date, the trustee shall determine the total value of the assets of the pooled trust fund, including the value of any interest accrued or dividends payable with respect thereto, shall be determined and securities valued as of the close of business in the applicable trading market coinciding with or next preceding the close of business on the New York Stock Exchange.

Common Collective Trust: The Pension Plans own units of the Common Collective Trust funds that they are utilizing in their portfolio. The value of each unit of any fund as of any valuation date shall be determined by calculating the total value of such fund’s assets as of the close of business on such valuation date, deducting its total liabilities as of such time and date, and then dividing the so-determined net asset value of such fund by the total number of units of such fund outstanding the date of valuation.

Insurance Contract: These investments are valued on a cash basis on any given valuation date which approximates fair value.

Structured Products: Investments are created through the process of financial engineering, (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities.

Other Plan Information

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

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2012			2011			2012			2011			2012			2011
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	325,944		$	280,623		$	30,223		$	24,725		$	50,141		$	46,304
Service cost	5,720			5,421			889			1,028			1,610			1,498
Interest cost	14,747			14,929			1,410			1,298			2,093			2,168
Actuarial (gain) loss	28,639			36,543			3,140			4,128			(4,430		)	3,017
Amendments	—			—			—			—			—			(160		)
Benefits paid	(11,815		)	(11,178		)	(1,269		)	(956		)	(5,190		)	(4,963		)
Plan curtailment liability reduction	—			(394		)	—			—			—			—
Medicare Part D accrued	—			—			—			—			289			188
Plan participants’ contributions	—			—			—			—			2,168			2,089
Projected benefit obligation at end of year	$	363,235		$	325,944		$	34,393		$	30,223		$	46,681		$	50,141

A reconciliation of the fair value of Plan assets was as follows (in thousands):



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2012			2011			2012		2011		2012			2011
Beginning market value of plan assets	$	221,722		$	220,164		$	—	$	—	$	4,319		$	4,564
Investment income (loss)	33,559			1,686			—		—		(3		)	1
Employer contributions	25,350			11,050			—		—		2,172			2,087
Retiree contributions	—			—			—		—		1,458			1,366
Benefits paid	(11,815		)	(11,178		)	—		—		(3,595		)	(3,713		)
Plan administrative expenses	—			—			—		—		—			14
Ending market value of plan assets	$	268,816		$	221,722		$	—	$	—	$	4,351		$	4,319

____________________


(a)	Asset of VEBA

Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Regulatory assets	$	94,199	$	93,423	$	—	$	—	$	6,438	$	9,161
Current liabilities	$	—	$	—	$	1,286	$	1,116	$	2,573	$	3,522
Non-current liabilities	$	94,410	$	104,214	$	33,180	$	30,953	$	39,807	$	42,313
Regulatory liabilities	$	—	$	—	$	—	$	—	$	2,174	$	590

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Accumulated benefit obligation - Black Hills Corporation	$	124,143	$	106,800	$	28,056	$	23,023	$	12,309	$	14,313
Accumulated benefit obligation - Black Hills Energy	202,897		184,345		453		446		25,868		25,842
Accumulated benefit obligation - Cheyenne Light	—		5,731		—		—		8,504		9,986
Total Accumulated Benefit Obligation	$	327,040	$	296,876	$	28,509	$	23,469	$	46,681	$	50,141

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plans
	2012			2011			2010			2012		2011		2010		2012			2011			2010
Service cost	$	5,720		$	5,421		$	6,131		$	889	$	1,028	$	685	$	1,610		$	1,498		$	1,509
Interest cost	14,747			14,929			15,091			1,410		1,298		1,284		2,093			2,168			2,446
Expected return on assets	(16,334		)	(16,955		)	(14,493		)	—		—		—		(78		)	(164		)	(208		)
Amortization of prior service cost	89			99			99			3		3		3		(500		)	(479		)	(309		)
Recognized net actuarial loss (gain)	9,630			4,540			3,126			807		510		285		887			677			636
Curtailment expense	—			13			57			—		—		—		—			—			—
Net periodic expense	$	13,852		$	8,047		$	10,011		$	3,109	$	2,839	$	2,257	$	4,012		$	3,700		$	4,074

Accumulated Other Comprehensive Income

In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at Dec. 31 were as follows (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012			2011
Net (gain) loss	$	12,090	$	11,472	$	7,283	$	6,894	$	2,097		$	2,556
Prior service cost (gain)	78		98		11		12		(1,784		)	(1,956		)
Total accumulated other comprehensive (income) loss	$	12,168	$	11,570	$	7,294	$	6,906	$	313		$	600

The amounts in Accumulated other comprehensive income (loss), Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2013 are as follows (in thousands):



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	8,005	$	515	$	313
Prior service cost (credit)	41		2		(325		)
Total net periodic benefit cost expected to be recognized during calendar year 2013	$	8,046	$	517	$	(12	)

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:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate	4.30	%	4.65	%	5.48	%	3.44	%	4.30	%	4.95	%	3.85	%	4.42	%	5.03	%
Rate of increase in compensation levels	3.84	%	3.77	%	3.79	%	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:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate:
Black Hills Corporation	4.68	%	5.50	%	6.05	%	4.70	%	5.00	%	6.10	%	4.35	%	5.00	%	5.90	%
Black Hills Energy	4.60	%	5.40	%	6.00	%	3.90	%	4.40	%	5.05	%	4.35	%	4.60	%	5.15	%
Cheyenne Light	N/A		5.55	%	6.05	%	N/A		N/A		N/A		4.65	%	5.50	%	6.00	%

Expected long-term rate of return on assets ^(a)	7.25	%	7.75	%	8.00	%	N/A		N/A		N/A		2.00	%	4.00	%	5.00	%
Rate of increase in compensation levels	3.75	%	3.79	%	4.20	%	5.00	%	5.00	%	5.00	%	NA		NA		N/A

_____________________________


(a)	The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 net periodic pension cost.

The healthcare benefit obligation was determined at Dec. 31 as follows:



	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	7.75	%	7.75	%
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	6.50	%	6.50	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

2011
Healthcare trend rate pre-65
Trend for next year	9.01	%	9.01	%	9.01	%
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	9.01	%	9.01	%	9.01	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

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 Dec. 31, 2012 Accumulated Postretirement Benefit Obligation			Impact on 2012 Service and Interest Cost
Increase 1%	$	2,082		$	127
Decrease 1%	$	(1,771	)	$	(107	)

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
2013	$	13,034	$	1,286	$	3,136
2014	$	13,953	$	1,463	$	3,350
2015	$	14,890	$	1,462	$	3,399
2016	$	15,982	$	1,540	$	3,419
2017	$	17,013	$	1,586	$	3,456
2018-2022	$	102,883	$	7,949	$	16,814

The entire disclosure for pension and other postretirement benefits.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Statement of Financial Accounting Standard (FAS)
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Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Text Block]

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 Power’s PPA with PacifiCorp, expiring Dec. 31, 2023, for the purchase of 50 megawatts 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 megawatts of capacity and energy to be transmitted annually by PacifiCorp.


•	Cheyenne Light’s PPA with Duke Energy’s Happy Jack wind site, expiring Sept. 3, 2028, provides up to 30 megawatts of wind energy from Happy Jack to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility output to Black Hills Power.


•	Cheyenne Light’s PPA with Duke Energy’s Silver Sage wind site, expiring Sept. 30, 2029, provides up to 30 megawatts of wind energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 megawatts of energy from Silver Sage to Black Hills Power.


•	Colorado Electric’s PPA with Cargill expiring Dec. 31, 2013, whereby Colorado Electric purchases 50 megawatts of economy energy.


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


•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 13, 2013. The agreement became effective March 14, 2011.

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



	2012		2011		2010
PPA with PacifiCorp	$	13,224	$	12,515	$	12,936
PPA with PSCo^(a)	$	—	$	97,988	$	110,575
Transmission services agreement with PacifiCorp	$	1,215	$	1,215	$	1,215
PPA with Happy Jack	$	1,988	$	1,955	$	2,815
PPA with Silver Sage	$	3,269	$	3,281	$	1,723
Busch Ranch Wind Project	$	502	$	—	$	—

_______________________


(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Other Supply Agreements

Our Gas 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.

Construction Obligations

We have purchase obligations related to Cheyenne Prairie construction. Our total obligations under these contracts were approximately $31 million, as of Dec. 31, 2012 which are expected to be paid in 2013 and 2014.

Future Minimum Payments

The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements (in thousands):



2013	$	187,301
2014	$	109,707
2015	$	108,024
2016	$	97,972
2017	$	86,564
Thereafter	$	222,002

Related Party Purchase Option

Cheyenne Light’s PPA for 60 megawatts of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on Dec. 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 megawatt which is the equivalent per megawatt of the estimated price of new construction of the Wygen III plant. This option purchase price is reduced annually by an amount equal to annual depreciation.

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 megawatts from our other generation facilities or from system purchases with reimbursement of costs by MDU.

•

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 megawatts 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;


•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through March 31, 2013.


•	Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III.


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

Related Party Lease

Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, provides 200 megawatts 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.

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 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 II, Lange CT, Wygen II, Wygen III and Wyodak 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 2042.

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 has 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 Aug. 31, 2012 with plans to retire Ben French, Osage and Neil Simpson I on or before 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 Dec. 31, 2013. This facility suspended operations Dec. 31, 2012. While the net book value of these plants is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

Solid Waste Disposal

Various materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been suspended, has an on-site ash impoundment that is near capacity. An application to close the impoundment was approved by the State of Wyoming on April 13, 2012. Site closure work is underway with post closure monitoring to continue for 30 years.

Our W.N. Clark plant, at which operations have been suspended, sends 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 have 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 10 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 $1.1 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. If required, it is expected to be completed by mid-2013. Both Nebraska sites will be required to monitor groundwater quality for a minimum two year period.

As of Dec. 31, 2012, our estimated liabilities for all of the MGP sites currently range from approximately $2.9 million to $6.3 million for which we had $3.1 million accrued for remediation of sites as of Dec. 31, 2012 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 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. It is alleged that the fire occurred when a high voltage electrical transmission line maintained by our electric utility subsidiary fell to the ground, and that electrical arcing from the downed line ignited dry grass or brush. The fire burned approximately 60,000 acres of land owned by private landowners, and by the United States Bureau of Land Management and the State of Wyoming. Our utility subsidiary received written claims from the State of Wyoming and a landowner seeking recovery of damages for alleged injury to timber, grass, fencing, fire suppression and rehabilitation costs. The total amount of damages currently claimed by the State of Wyoming and a landowner is approximately $8.0 million. We have been notified that additional private landowner claims are forthcoming. Our investigation into the cause and origin of the fire is still pending. Based upon information developed in our investigation to this date, we expect to deny and will vigorously defend all claims arising out of the fire. Given the uncertainty of litigation, however, a loss relating to the fire and the litigation is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing, and because we expect further claims to be presented by other parties. Although we cannot predict the outcome of our investigation or the viability of potential claims, based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material effect on our financial statements.

The entire disclosure for commitments and contingencies.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
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-Section 50
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.25)
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 440
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Guarantees

12 Months Ended

Dec. 31, 2012

Guarantees [Abstract]

Guarantees [Text Block]

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 guarantees of debt obligations, contractual performance obligations and indemnification for reclamation and surety bonds.

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



	Maximum Exposure at
Nature of Guarantee	Dec. 31, 2012		Expiration
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric⁽²⁾	33,264		March 29, 2013
Indemnification for subsidiary reclamation/surety bonds ⁽³⁾	54,509		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Colorado Gas ⁽⁴⁾	10,000		July 31, 2013
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply ⁽⁵⁾	7,500		June 30, 2013
	$	175,273

_______________________

(1)

We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.


(2)	We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.


(3)	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.


(4)	We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.


(5)	We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.

Oil and Gas Reserves (Unaudited)

12 Months Ended

Dec. 31, 2012

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 1,200 gross developed oil and gas wells in 9 states and holds leases on approximately 268,636 net acres.

Costs Incurred

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



	2012		2011		2010
Acquisition of properties:
Proved	$	2,437	$	673	$	—
Unproved	33,052		8,317		3,846
Exploration costs	115		44,384		8,159
Development costs	73,877		38,638		25,264
Asset retirement obligations incurred	158		43		1,228
Total costs incurred	$	109,639	$	92,055	$	38,497

Reserves

The following table summarizes BHEP’s quantities of proved developed and undeveloped oil and natural gas reserves, estimated using SEC-defined product prices, as of December 31, 2012, 2011 and 2010, 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.



	2012						2011						2010
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	6,223			95,904			5,940			95,456			5,274			87,660
Production ^(a)	(560		)	(8,686		)	(452		)	(8,526		)	(376		)	(8,484		)
Additions - acquisitions (sales)^(b)	(2,025		)	(3,070		)	(84		)	—			(13		)	(377		)
Additions - extensions and discoveries	449			2,898			927			29,664			1,145			1,710
Revisions to previous estimates ^(c)	29			(31,061		)	(108		)	(20,690		)	(90		)	14,947
Balance at end of year	4,116			55,985			6,223			95,904			5,940			95,456

Proved developed reserves at end of year included above	3,851			54,086			4,830			71,867			4,434			67,656

Proved undeveloped reserves at the end of year included in above	265			1,901			1,393			24,037			1,506			27,800

NYMEX prices	$	94.71		$	2.76		$	96.19		$	4.12		$	79.43		$	4.38

Well-head reserve prices	$	85.31		$	2.24		$	88.49		$	3.59		$	70.82		$	3.45

________________________


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


(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.


(c)	Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.

Reserve additions totaled 5.6 Bcfe, replacing 46 percent of production. Additions resulted from drilling in the Williston Basin, San Juan, Piceance and Powder River Basins. Drilling in Williston Basin (Bakken Shale) accounted for 3.1 Bcfe, Piceance Basin (Mancos Shale) 1.9 Bcfe, Powder River Basin 0.3 Bcfe and recompletions in the San Juan Basin 3.0 Bcfe. Capital spending in 2012 was increased to accommodate the Williston Bakken drilling and to continue evaluating the development potential of the Mancos Shale under our leasehold in the San Juan and Piceance Basins. Additionally, exploratory investments were made to develop future opportunities. Future capital spending rates are anticipated to be dependent on product prices.

SEC regulations require that proved undeveloped locations meet the test of being developed within five years of being categorized as proved. Approximately 2.4 Bcfe was removed from previous estimates due to five year reserve aging of the PUD locations in the Bear Paw Uplift, the Piceance Basin and the Wind River Basin. Negative revisions to previous estimates were mostly due to lower natural gas prices received at the well head. Approximately 27.1 Bcfe of the negative revision was due to low commodity prices. Most of the negative revisions were located in the San Juan Basin 11.5 Bcfe; Piceance Basin 13.9 Bcfe; Wind River Basin 0.8 Bcfe; Oklahoma Basins 0.5 Bcfe; and Bear Paw Uplift and other basins 0.4 Bcfe. Additionally, a 0.5 Bcfe behind pipe reserve in the Piceance Basin was dropped. Overall, approximately 1.6 Bcfe was dropped in various basins for small performance downgrades which were offset by performance upgrades in some basins.

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 during the year.


•	In 2012, we sold 29 year-end 2011 PUD locations as part of an asset sale in the Williston Basin that represented $41.7 million in investment and 9.5 Bcfe reserves.


•	The San Juan Basin has three PUD locations (approximately 8.1 Bcfe and $15.1 million investment) and three PUD locations in the Piceance Basin (12.1 Bcfe and $24.7 million investment) were dropped due to low commodity pricing.


•	Approximately 34 PUD locations were dropped for reserve aging. Of those, 32 PUD locations were in the Bear Paw Uplift (1.0 Bcfe) and two PUD locations were in the Piceance Basin (1.4 Bcfe).


•	We invested $5.7 million to develop three Williston Basin PUD locations in our remaining Williston Basin assets. PUD locations, proved reserves and future development costs associated with the Williston Basin during 2012 and at Dec. 31, 2012 were:



	As of Dec. 31, 2012
Williston Basin	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Existed	0.9	3	$	4.9
Added	0.5	8	$	2.1
Williston Basin	1.4	11	$	7.0


•	None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised.

Capitalized Costs

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



	2012			2011			2010
Unproved oil and gas properties	$	59,526		$	28,656		$	28,160
Proved oil and gas properties	662,444			674,494			592,978
Gross capitalized costs	721,970			703,150			621,138

Accumulated depreciation, depletion and amortization and valuation allowances ^(a)	(534,777		)	(361,173		)	(334,955		)
Net capitalized costs	$	187,193		$	341,977		$	286,183

__________________


(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Results of Operations

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



	2012			2011			2010
Revenue	$	79,072		$	79,808		$	74,164

Production costs	23,483			23,820			21,922
Gain on sale of assets	(29,129		)	—			—
Depreciation, depletion and amortization and valuation provisions	37,323			34,415			29,013
Impairment of long-lived assets	26,868			—			—
Total costs	58,545			58,235			50,935
Results of operations from producing activities before tax	20,527			21,573			23,229

Income tax benefit (expense)	(7,082		)	(7,442		)	(8,014		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	13,445		$	14,131		$	15,215

Unproved properties not subject to amortization at Dec. 31, 2012, 2011 and 2010 consisted mainly of exploration cost on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.7 million, $0.9 million and $0.8 million of interest during 2012, 2011 and 2010, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined. We expect the exploration cost listed below to be added to the cost pool in the next year.

The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2012 and notes the year in which the associated costs were incurred (in thousands):



	2012		2011		2010			Prior		Total
Leasehold acquisition cost	$	35,539	$	638	$	2,138		$	16,709	$	55,024
Exploration cost	328		—		—			—		328
Capitalized interest	683		60		(36		)	3,467		4,174
Total	$	36,550	$	698	$	2,102		$	20,176	$	59,526

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 Dec. 31 (in thousands):



	2012			2011			2010
Future cash inflows	$	502,769		$	931,637		$	764,585
Future production costs	(186,695		)	(280,910		)	(256,455		)
Future development costs	(8,462		)	(92,233		)	(73,805		)
Future income tax expense	(69,877		)	(157,922		)	(111,666		)
Future net cash flows	237,735			400,572			322,659
10 percent annual discount for estimated timing of cash flows	(101,632		)	(197,215		)	(154,551		)
Standardized measure of discounted future net cash flows	$	136,103		$	203,357		$	168,108

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



	2012			2011			2010
Standardized measure - beginning of year	$	203,357		$	168,108		$	129,108
Sales and transfers of oil and gas produced, net of production costs	(48,905		)	(52,914		)	(40,282		)
Net changes in prices and production costs	(42,639		)	57,087			57,380
Extensions, discoveries and improved recovery, less related costs	19,870			31,179			17,076
Changes in future development costs	43,854			43,809			(17,125		)
Development costs incurred during the period	21,931			18,940			4,975
Revisions of previous quantity estimates	(86,277		)	(58,211		)	27,513
Accretion of discount	25,509			19,655			13,434
Net change in income taxes	36,578			(23,283		)	(23,233		)
Purchases of reserves	—			—			—
Sales of reserves ^(a)	(37,175		)	(1,013		)	(738		)
Standardized measure - end of year	$	136,103		$	203,357		$	168,108

________


(a)	Reflects sale of Williston Basin assets

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

Sale of Operating Assets

12 Months Ended

Dec. 31, 2012

Sale of Assets [Abstract]

Property, Plant and Equipment Significant Disposals [Text Block]

SALE OF ASSETS

Partial Sale of Electric Utilities Assets

On Sept. 18, 2012, Colorado Electric completed the sale of an undivided 50 percent ownership interest in the Busch Ranch Wind Farm to AltaGas for $25.0 million. Colorado Electric retains the remaining undivided interest and will be the operator of this jointly owned facility. Commercial operation of the newly constructed wind farm commenced on Oct. 16, 2012. Colorado Electric will purchase AltaGas’s interest, or approximately 14.5 megawatts, in the energy produced by the wind farm through a REPA expiring on Oct. 16, 2037.

On July 14, 2010, Black Hills Power sold a 23 percent ownership interest in Wygen III to the City of Gillette for $62.0 million. The Participation Agreement provides that the City of Gillette will pay Black Hills Power for administrative services and share in the costs of operating the plant for the life of the facility. The amount of net fixed assets sold totaled $55.8 million. Black Hills Power recognized a gain on the sale of $6.2 million.

Partial Sale of Oil and Gas Assets

On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Three Forks shale assets in the Williston Basin in North Dakota. The sale included approximately 73 gross wells, 28,000 net leasehold acres and had an effective date of July 1, 2012.

Our Oil and Gas segment follows the full-cost method of accounting for oil and gas activities. Typically this methodology does not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is allowed when such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Sept. 27, 2012 sale of the majority of the Williston Basin assets significantly alters the relationship and accordingly we have recorded a gain of $29.1 million with the remainder of the proceeds recorded as a reduction in the full cost pool. This reduction in the full cost pool significantly decreased the depreciation, depletion and amortization rate for the remainder of 2012.

Net cash proceeds were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314
Less:
Post close adjustments	2,793
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
Net cash proceeds	$	227,860

_____________


*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Partial Sale of Gas Utilities Assets

On March 1, 2010, Nebraska Gas sold certain assets to Metropolitan Utilities District as a result of annexation proceedings by the City of Omaha, Nebraska. Nebraska Gas received $6.1 million in cash and recognized a $2.7 million pre-tax gain on the sale.

Discontinued Operations

12 Months Ended

Dec. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

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. Assets and liabilities of the discontinued operations have been classified and reflected on the accompanying Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassification on a consistent basis.

Energy Marketing Segment

On Feb. 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 on Dec. 31, 2012 were approximately $165.0 million, subject to final post-closing adjustments. The proceeds represent $107.5 million received from the buyer and $57.5 million cash retained from Enserco before closing.

Pursuant to the provisions of the Stock Purchase Agreement, disputes regarding post-closing purchase price adjustments are subject to arbitration before a nationally-recognized accounting firm and all other disputes are subject to the indemnification procedures in the agreement. The buyer originally demanded an amount totaling $7.2 million, characterizing all claims in such demand as purchase price adjustments. We contested certain claims in the buyer's demand, including whether certain claims were properly characterized as purchase price adjustments, but reached a partial settlement and paid the buyer the sum of $1.4 million. The parties were unable to reach a negotiated agreement regarding the balance of the claims.

In December 2012, we agreed to arbitrate the claims that we believe are properly characterized as purchase price adjustments, but objected to the arbitration of the claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator, in January 2013 the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On Feb. 7, 2013, the buyer filed a petition in the United States District Court for the District of Colorado applying for an order compelling arbitration on all of the disputed claims. We will respond to this litigation, requesting the court to deny the buyer's application. The filing of this petition does not alter our characterization or evaluation of the original claim.

Operating results of the Energy Marketing segment included in Income (loss) from discontinued operations, net of tax on the accompanying Consolidated Statements of Income were as follows (in thousands):



For the Years Ended Dec. 31,	2012			2011			2010

Revenue	$	(604	)	$	41,101		$	27,999

Pre-tax income (loss) from discontinued operations	(6,061		)	14,838			8,673
Pre-tax gain (loss) on sale	(4,184		)	—			—
Income tax (expense) benefit	3,268			(5,473		)	(3,129		)
Income (loss) from discontinued operations, net of tax^(a)	$	(6,977	)	$	9,365		$	5,544

________


(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment.

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the Consolidated Balance Sheets were as follows (in thousands) as of:



	Dec. 31, 2011
Other current assets	$	280,221
Derivative assets, current and non-current	52,859
Property, plant and equipment, net	5,828
Goodwill	1,435
Other non-current assets	508
Other current liabilities	(132,951		)
Derivative liabilities, current and non-current	(26,084		)
Other non-current liabilities	(14,894		)
Net assets	$	166,922

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information [Text Block]

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 2012 and 2011.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2012
Revenue	$	365,851		$	242,363		$	246,808		$	318,862
Operating income^(a)	$	70,048		$	20,591		$	77,810		$	75,262
Income (loss) from continuing operations^{(b) (c)}	$	35,271		$	(12,323	)	$	34,623		$	30,934
Income (loss) from discontinued operations	$	(5,484	)	$	(1,160	)	$	(166	)	$	(167	)
Net income (loss) available for common stock ^{(b) (c)}	$	29,787		$	(13,483	)	$	34,457		$	30,767

Income (loss) per share for continuing operations - basic	$	0.81		$	(0.28	)	$	0.79		$	0.70
Income (loss) per share for discontinued operations - basic	(0.13		)	(0.03		)	—			—
Income (loss) per share - basic	$	0.68		$	(0.31	)	$	0.79		$	0.70

Income (loss) per share for continuing operations - diluted	$	0.80		$	(0.28	)	$	0.78		$	0.70
Income (loss) per share for discontinued operations - diluted	(0.12		)	(0.03		)	—			—
Income (loss) per share - diluted	$	0.68		$	(0.31	)	$	0.78		$	0.70

Dividends paid per share	$	0.370		$	0.370		$	0.370		$	0.370

Common stock prices - High	$	35.82		$	34.31		$	36.28		$	37.00
Common stock prices - Low	$	32.18		$	31.32		$	30.29		$	33.51

__________________________


(a)	Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.


(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.


(c)	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.



	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2011
Revenue	$	400,835		$	260,649	$	249,523		$	361,181
Operating income	$	58,367		$	36,160	$	39,572		$	52,140
Income (loss) from continuing operations ^(a)	$	29,068		$	3,706	$	(11,163	)	$	18,754
Income (loss) from discontinued operations	$	(2,158	)	$	4,046	$	638		$	6,839
Net income (loss) available for common stock ^(a)	$	26,910		$	7,752	$	(10,525	)	$	25,593

Earnings (loss) per share for continuing operations - basic	$	0.74		$	0.09	$	(0.29	)	$	0.45
Earnings (loss) per share for discontinued operations - basic	(0.05		)	0.11		0.02			0.16
Earnings (loss) per share - basic	$	0.69		$	0.20	$	(0.27	)	$	0.61

Earnings (loss) per share for continuing operations - diluted	$	0.73		$	0.09	$	(0.29	)	$	0.44
Earnings (loss) per share for discontinued operations - diluted	(0.05		)	0.10		0.02			0.16
Earnings (loss) per share - diluted	$	0.68		$	0.19	$	(0.27	)	$	0.60

Dividends paid per share	$	0.365		$	0.365	$	0.365		$	0.365

Common stock prices - High	$	33.64		$	34.85	$	32.22		$	34.47
Common stock prices - Low	$	29.76		$	28.12	$	25.83		$	29.10

__________________________


(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

Condensed Statement of Income [Member]

Schedule I Disclosures for Parent Company Only

12 Months Ended

Dec. 31, 2012

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF INCOME



	2012			2011			2010
	(in thousands)

Revenue	$	—		$	—		$	—
Operating expenses	831			772			735
Operating income (loss)	(831		)	(772		)	(735		)

Other income (expense):
Equity income (loss) in earnings of subsidiaries	93,479			87,150			88,627
Interest expense	(19,665		)	(15,229		)	(14,985		)
Unrealized (loss) gain on interest rate swaps, net	1,882			(42,010		)	(15,193		)
Interest income	32			3			22
Other income (expense), net	49			(42		)	34
Total other income (expense)	75,777			29,872			58,505
Income (loss) before income taxes	74,946			29,100			57,770
Income tax benefit (expense)	6,582			20,630			10,915
Net income (loss) available for common stock	$	81,528		$	49,730		$	68,685

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Statement of Comprehensive Income [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)



Years ended (in thousands)	Dec. 31, 2012			Dec. 31, 2011			Dec. 31, 2010

Net income available for common stock	$	81,528		$	49,730		$	68,685

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $296, $4,135 and $674, respectively)	(542		)	(7,609		)	(1,307		)
Benefit plan liability adjustments - prior service (costs) (net of tax of $86, $176 and $111, respectively)	(157		)	(325		)	(214		)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $887, $1,708 and $(636), respectively)	(1,268		)	(2,831		)	1,336
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $534, $(709) and $2,498, respectively)	(643		)	1,468			(4,232		)
Other comprehensive income (loss), net of tax, including earnings (loss) of consolidated subsidiaries	(2,610		)	(9,297		)	(4,417		)

Comprehensive income (loss)	$	78,918		$	40,433		$	64,268

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Balance Sheet [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED BALANCE SHEETS



At Dec. 31,	2012		2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,266	$	3,114
Accounts receivable — affiliates, current	2,194		1,445
Notes receivable — affiliates, current	637,586		453,216
Income tax receivable, net	5,843		8,653
Deferred income tax assets, net, current	29,779		36,951
Other current assets	4,887		7,178
Total current assets	681,555		510,557

Property and Equipment	1,135		1,135

Investments in subsidiaries	1,194,501		1,339,024

Notes receivable — affiliate, non-current	250,000		575,000
Deferred income tax assets, net, non-current	41,494		29,454
Other long-term assets	4,014		4,834
Total other assets, non-current	295,508		609,288

TOTAL ASSETS	$	2,172,699	$	2,460,004

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable -- affiliate, current	$	565	$	5,202
Derivative liabilities, current	91,617		78,502
Notes payable	277,000		345,000
Notes payable — affiliate, current	1,032		1,754
Current maturities of long-term debt	100,000		—
Other current liabilities	9,943		12,070
Total current liabilities	480,157		442,528

Derivative liabilities, non-current	9,252		31,368

Long-term debt	450,000		774,959
Note payable — affiliate, non-current	781		1,813
Total long-term debt	450,781		776,772

Total stockholders’ equity	1,232,509		1,209,336

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,172,699	$	2,460,004

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Statement of Cash Flows [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

BLACK HILLS CORPORATION (PARENT COMPANY)

CONDENSED STATEMENTS OF CASH FLOWS



Years ended Dec. 31,	2012			2011			2010
	(in thousands)
Operating activities:
Net income (loss) available for common stock	$	81,528		$	49,730		$	68,685
Loss from discontinued operations, net of tax	—			—			—
Income from continuing operations	81,528			49,730			68,685
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities —
Equity in earnings of subsidiaries	(93,479		)	(87,150		)	(88,627		)
Dividend from subsidiaries	—			14,500			6,298
Stock compensation	8,271			5,643			5,637
Unrealized mark-to-market (gain) loss on certain interest rate swaps	(1,882		)	42,010			15,193
Derivative fair value adjustments	(4,339		)	2,291			(6,384		)
Deferred income taxes	(8,116		)	2,599			(34,452		)
Other adjustments, net	3,909			4,376			2,508
Change in operating assets and liabilities —
Accounts receivable and other current assets	6,541			(5,141		)	2,198
Accounts payable and other current liabilities	(6,764		)	3,550			4,846
Other operating activities	(3,477		)	550			(2,514		)
Net cash provided by (used in) operating activities	(17,808		)	32,958			(26,612		)

Investing activities:
Property, plant and equipment additions	—			(1,135		)	—
Decrease (Increase) in advances to affiliates	96,073			(258,117		)	(216,337		)
Other investing activities	450			—			—
Net cash provided by (used in) investing activities	96,523			(259,252		)	(216,337		)

Financing activities:
Dividends paid on common stock	(65,262		)	(59,202		)	(56,467		)
Common stock issued	4,726			123,041			3,246
Short-term borrowings -- repayments	(271,753		)	(821,300		)	(770,000		)
Short-term borrowings -- issuances	203,753			1,017,300			854,500
Increase (Decrease) in Notes payable to affiliates	275,806			(25,302		)	14,995
Long-term debt — issuance	—			—			200,000
Long-term debt — repayment	(225,000		)	—			—
Other financing activities	(2,833		)	(5,348		)	(5,379		)
Net cash provided by financing activities	(80,563		)	229,189			240,895
Net change in cash and cash equivalents	(1,848		)	2,895			(2,054		)

Cash and cash equivalents beginning of year	3,114			219			2,273
Cash and cash equivalents end of year	$	1,266		$	3,114		$	219



Supplemental Cash Flow Information
Years ended	2012			2011			2010
	(in thousands)
Non-cash investing and financing activities-
Non-cash adjustment to notes receivable from affiliates	$	40,039		$	—		$	62,019
Non-cash adjustment to notes payable to affiliates	$	(277,560	)	$	—		$	13,874
Non-cash dividend, net of non-cash contributions, from affiliates	$	237,521		$	—		$	—

Cash (paid) refunded during the period for-
Interest	$	(18,550	)	$	(14,667	)	$	(56,464	)
Income taxes	$	3,911		$	23,830		$	(504	)

The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

Condensed Footnotes Of Parent [Member]

Condensed Financial Statements, Captions [Line Items]

Condensed Financial Information of Parent Company Only Disclosure [Text Block]

NOTES TO BLACK HILLS CORPORATION (PARENT COMPANY) CONDENSED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION

Pursuant to rules and regulations of the SEC, the unconsolidated condensed financial statements of Black Hills Corporation do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report on Form 10-K.

Dividends paid and distributed to Black Hills Corporation (the Parent) from its subsidiaries were as follows (in thousands):



	2012		2011		2010
Cash dividends paid to Parent by subsidiaries	$	—	$	14,500	$	6,298
Non-Cash dividends, net of non-cash contributions, distributed to Parent by subsidiaries	$	237,521	$	—	$	—

(2) NOTES RECEIVABLE AND NOTES PAYABLE

Black Hills Corporation has notes receivable and notes payable with affiliates under Utility Money Pool Agreements and Non-Utility Money Pool Agreements. Borrowings under these agreements bear interest at the weighted average daily cost of external funds as defined under the agreements.

Additionally, Black Hills Corporation has a Revolving Credit Facility and corporate term loans with various banks. Our credit facility and debt securities contain certain restrictive financial covenants. At December 31, 2012, we were in compliance with all of these covenants. See Note 9 to Notes to Consolidated Financial Statements on this Annual Report on Form 10-K.

(3) LONG-TERM DEBT

Long-term debt outstanding at Dec. 31 was as follows (in thousands):



	Due Date	Interest Rate	2012		2011
Senior unsecured notes due 2013 ^(a)	May 15, 2013	6.50%	$	—	$	225,000
Unamortized discount on notes due 2013^(a)			—		(41		)
Senior unsecured notes due 2014 ^{(b) (e)}	May 15, 2014	9.00%	250,000		250,000
Senior unsecured notes due 2020 ^{(c) (e)}	July 15, 2020	5.88%	200,000		200,000
Long-term term loan^(d)	Sept. 30, 2013	1.63%	100,000		100,000
Total long-term debt			550,000		774,959
Less current maturities			100,000		—
Net long-term debt			$	450,000	$	774,959

_______________


(a)	This note was repaid on Oct. 31, 2012. This senior unsecured note had been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2011.


(b)	This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.


(c)	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.


(d)	This term loan has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, current on the Parent’s Condensed Balance Sheets for 2012.


(e)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.

Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at December 31, 2012.

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



2013	$	100,000
2014	$	250,000
2015	$	—
2016	$	—
2017	$	—
Thereafter	$	200,000

(4) GUARANTEES

(5) RISK MANAGEMENT ACTIVITIES

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. See Note 3 of Notes to Consolidated Financial Statements on this Annual Report on Form 10-K for further information.

On Dec. 31 our interest rate swaps and related balances were as follows (dollars in thousands):



	2012						2011
	Interest Rate Swaps			De-designated Interest Rate Swaps			Interest Rate Swaps			De-designated Interest Rate Swaps
Notional^(a)	$	75,000		$	250,000		$	75,000		$	250,000
Weighted average fixed interest rate	4.97		%	5.67		%	4.97		%	5.67		%
Maximum terms in years	4.0			1.0			5.0			2.0
Current derivative liabilities	$	3,469		$	88,148		$	3,207		$	75,295
Non-current derivative liabilities	$	9,252		$	—		$	10,672		$	20,696
Pre-tax accumulated other comprehensive (loss)	$	(12,721	)	$	—		$	(13,879	)	$	—
Pre-tax gain (loss)	$	—		$	1,882		$	—		$	(42,010	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	—

________________________

(a)

Under the terms of the Black Hills Wyoming project financing, Black Hills Wyoming was required to become a party to hedging agreements fixing the interest rate on a portion of the principal amount of the debt. To accomplish this, two existing swap agreements totaling $75.0 million were amended and transferred to Black Hills Wyoming so that the Parent and Black Hills Wyoming are now both jointly and severally liable for the full amount of the obligations under the swap agreements. The balance in AOCI of the Parent was frozen at that point in time and is being amortized over the remaining life of the swaps through the quarterly settlement process.

Based on December 31, 2012 market interest rates and balances, a loss of approximately $3.5 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the future periods as market interest rates fluctuate.

(6) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	1,266	$	1,266	$	3,114	$	3,114
Notes payable ^(a)	$	277,000	$	277,000	$	345,000	$	345,000
Long-term debt ^(b)	$	550,000	$	615,239	$	774,959	$	851,241

______________


(a)	Fair value approximates carrying 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)

Cash and Cash Equivalents

Notes Payable

Notes Payable represent our short-term corporate term loan and borrowings under our Revolving Credit Facility.

Long-Term Debt

For additional information see Note 3 of these Black Hills Corporation (the Parent) Condensed Financial Statements.

(7) COMMON STOCK

Forward Equity Issuance

In November 2011, we settled the equity forward agreement. For additional information see Note 11 of Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

(8) COMMITMENTS AND CONTINGENCIES

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 condensed financial statements 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 condensed financial statements.

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

Valuation and Qualifying Accounts Disclosure [Line Items]

Schedule II Consolidated Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2012

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

SCHEDULE II



BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2012, 2011, AND 2010

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:
2012	$	1,661	$	—	$	1,913	$	3,822	$	(6,628	)	$	768
2011	$	2,295	$	—	$	3,042	$	5,369	$	(9,045	)	$	1,661
2010	$	3,683	$	—	$	1,898	$	2,196	$	(5,482	)	$	2,295

Business Description and Significant Accounting Policies Business Description (Policies)	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]
Segment Reporting, Policy [Policy Text Block]	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, Wyo. 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, Wyo. Oil and Gas, which is conducted through BHEP and its subsidiaries, engages in crude oil and natural gas exploration and production activities located 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 Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. See Note 23 for additional information.
Use of Estimates, Policy [Policy Text Block]	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.
Consolidation, Policy [Policy Text Block]	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 17. Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie and the BHEP gas processing plant. See Note 7 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 23 for additional information.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	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 The Black Hills Wyoming project financing requires that we maintain cash accounts for various specified purposes. We do not readily have access to these accounts and can only withdraw funds upon meeting certain requirements. Therefore, we have classified these amounts as restricted cash.
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Utilities Group primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Non-regulated Energy Group consists of amounts due from sales of coal, crude oil and natural gas, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Revenue Recognition, Policy [Policy Text Block]	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.
Inventory, Policy [Policy Text Block]	Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represent 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, Policy [Policy Text Block]	Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, 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. 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.
Industry Specific Policies, Oil and Gas [Policy Text Block]	Oil and Gas Operations We account for our oil and gas activities under the full cost method. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. However, we recognized a gain on the sale of a majority of our Williston Basin assets in 2012. See Note 22 for further discussion. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. These costs are generally expected to be included in costs to be amortized within the term of the underlying lease agreement which varies in length. Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at an SEC required rate, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. As a result of lower natural gas prices, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment in 2012. No ceiling test write-down was recorded in 2011 or 2010. See Note 12 for additional information. The SEC definition of “reliable technology” permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This definition allows, but does not require us, to calculate PUDs to be booked at more than one location away from a producing well. We elected to include PUDs of only one location away from a producing well in our volume reserve estimate. See information on our oil and gas drilling activities in Note 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, Policy [Policy Text Block]	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 Nov. 30 each year (or more frequently if impairment indicators arise). We performed our annual goodwill impairment tests as of Nov. 30, 2012. 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, Policy [Policy Text Block]	Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset. 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 of Financial Instruments, Policy [Policy Text Block]	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, Policy [Policy Text Block]	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. 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 loss or gain 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.
Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]	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, Policy [Policy Text Block]	Deferred Financing Costs Deferred financing costs are amortized using the effective interest method over the useful life of the related debt
Property, Plant and Equipment, Preproduction Design and Development Costs [Policy Text Block]	Development Costs According to accounting standards for business combinations, we expense, when incurred, development and acquisition costs associated with corporate development activities prior to acquiring or beginning construction of a project. Expensed development costs are included in Other operating expenses on the accompanying Consolidated Statements of Income.
Legal Costs, Policy [Policy Text Block]	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.
Public Utilities, Policy [Policy Text Block]	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 are not allowed a return. 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 Tax, Policy [Policy Text Block]	Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. We classify deferred tax assets and liabilities into current and non-current amounts based on the nature of the related assets and liabilities. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax asset will not be realized. It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. Another acceptable accounting method and an exception to this general policy currently in our regulated businesses is to apply the deferral method whereby the credit is amortized as a reduction of income tax expense over the useful lives of the related property. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with 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, Policy [Policy Text Block]	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 (loss) per share is computed by including all dilutive common shares outstanding during each year.
Discontinued Operations, Policy [Policy Text Block]	Discontinued Operations Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. Additionally, in accordance with GAAP, indirect corporate costs previously allocated to a disposal group cannot be reclassified to discontinued operations. Assets of discontinued operations and Liabilities of discontinued operations on the accompanying Consolidated Balance Sheets included the assets and liabilities of Enserco Energy Inc. See Note 23 for additional information.

Business Description and Significant Accounting Policies Business Description (Tables)

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

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



2012	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	54,482	$	23,843	$	(527	)	$	77,798
Gas Utilities	31,495		39,962		(222		)	71,235
Power Generation	16		—		—			16
Coal Mining	2,247		—		—			2,247
Oil and Gas	11,622		—		(19		)	11,603
Corporate	799		—		—			799
Total	$	100,661	$	63,805	$	(768	)	$	163,698



2011	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric Utilities	$	42,773	$	21,151	$	(545	)	$	63,379
Gas Utilities	39,353		38,992		(1,011		)	77,334
Power Generation	282		—		—			282
Coal Mining	4,056		—		—			4,056
Oil and Gas	11,282		—		(105		)	11,177
Corporate	546		—		—			546
Total	$	98,292	$	60,143	$	(1,661	)	$	156,774

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):



	Dec. 31, 2012		Dec. 31, 2011
Materials and supplies	$	43,397	$	40,838
Fuel - Electric Utilities	8,589		8,201
Natural gas in storage held for distribution	25,657		35,025
Total materials, supplies and fuel	$	77,643	$	84,064

Goodwill

Goodwill balances were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at Dec. 31, 2010	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at Dec. 31, 2012	$	250,487	$	94,144	$	8,765	$	353,396

Intangible Assets

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



	2012			2011			2010
Intangible assets, net, beginning balance	$	3,843		$	4,069		$	4,309
Additions (adjustments)	—			—			—
Amortization expense *	(223		)	(226		)	(240		)
Intangible assets, net, ending balance	$	3,620		$	3,843		$	4,069

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of 2013, 2014, 2015, 2016, and 2017.

Regulatory Assets and Liabilities

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



	Maximum Recovery
	or Settlement Period	As of		As of
	(in years)	Dec. 31, 2012		Dec. 31, 2011
Regulatory assets
Deferred energy and fuel costs adjustments - current^(a)	1	$	16,005	$	33,526
Deferred gas cost adjustments and gas price derivatives^(a)	7	20,741		26,208
AFUDC^(b)	45	12,416		12,482
Employee benefit plans ^(c)	13	115,521		120,708
Environmental^(a)	subject to approval	1,792		1,770
Asset retirement obligations^(a)	44	3,247		3,097
Bond issue cost^(a)	25	3,561		3,704
Renewable energy standard adjustment ^(a)	5	19,484		20,095
Flow through accounting^(d)	35	16,620		12,191
Other regulatory assets^(a)	15	10,006		8,349
		$	219,393	$	242,130

Regulatory liabilities
Deferred energy and gas costs^(a)	1	$	21,091	$	16,961
Employee benefit plans^(e)	13	59,362		59,455
Cost of removal^(a)	44	53,526		42,257
Other regulatory liabilities^(f)	25	7,305		5,775
		$	141,284	$	124,448

__________


(a)	Recovery of costs, but 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 of costs, we are allowed a return on approximately $24.6 million.


(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.


(e)	Approximately $13.2 million is included in our rate base calculations as a reduction to rate base.


(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

Earnings Per Share Reconciliation

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



	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Income (loss) from continuing operations	$	88,505	$	40,365	$	63,141

Weighted average shares - basic *	43,820		39,864		38,916
Dilutive effect of:
Stock options	13		19		14
Restricted stock	173		153		107
Equity forward instrument	—		—		29
Other dilutive effects	67		45		25
Weighted average shares - diluted	44,073		40,081		39,091

_______________


*	In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

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):



	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock options	95	105	158
Restricted stock	53	17	1
Other stock	15	19	1
Anti-dilutive shares excluded from computation of earnings (loss) per share	163	141	160

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

Risk Management Activities Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Derivatives Instruments Statements of Financial Performance Financial Position Location and Notional Amounts [Table Text Block]

Our interest rate swaps and related balances were as follows (dollars in thousands) as of:



	Dec. 31, 2012						Dec. 31, 2011
	Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps^(b)			Interest Rate Swaps ^(a)			De-designated Interest Rate Swaps^(b)
Notional	$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.0			1.0			5.0			2.0
Derivative liabilities, current	$	7,039		$	88,148		$	6,513		$	75,295
Derivative liabilities, non-current	$	16,941		$	—		$	20,363		$	20,696
Pre-tax accumulated other comprehensive income (loss)	$	(23,980	)	$	—		$	(26,876	)	$	—
Pre-tax gain (loss)	$	—		$	1,882		$	—		$	(42,010	)
Cash collateral receivable (payable) included in derivatives	$	—		$	5,960		$	—		$	—

___________________


(a)	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.


(b)	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.

Schedule of Derivative Instruments, Gain (Loss) [Table Text Block]

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31. exclusive of cash collateral (in thousands):



		2012				2011
	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	$	2,874	$	—	$	8,739	$	—
Commodity derivatives	Derivative assets - non-current	510		—		1,919		—
Commodity derivatives	Derivative liabilities - current	—		1,993		—		2,559
Commodity derivatives	Derivative liabilities - non-current	—		821		—		818
Interest rate swaps	Derivative liabilities - current	—		7,038		—		6,513
Interest rate swaps	Derivative liabilities - non-current	—		16,941		—		20,363
Total derivatives designated as hedges		$	3,384	$	26,793	$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	362	$	—	$	—	$	9,572
Commodity derivatives	Derivative assets - non-current	—		—		—		(52		)
Commodity derivatives	Derivative liabilities - current	1,180		4,957		—		—
Commodity derivatives	Derivative liabilities - non-current	406		5,153		—		7,156
Interest rate swaps	Derivative liabilities - current	—		94,108		—		75,295
Interest rate swaps	Derivative liabilities - non-current	—		—		—		20,696
Total derivatives not designated as hedges		$	1,948	$	104,218	$	—	$	112,667

Schedule of Derivatives Instruments Statements of Financial Performance Financial Position Location and Notional Amounts [Table Text Block]

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:



	Dec. 31, 2012				Dec. 31, 2011
	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)	528,000		8,215,500		528,000			5,406,250
Maximum terms in years ^(b)	1		0.75		1.25			1.75
Derivative assets, current	$	1,405	$	1,831	$	729		$	8,010
Derivative assets, non-current	$	297	$	170	$	771		$	1,148
Derivative liabilities, current	$	847	$	507	$	2,559		$	—
Derivative liabilities, non-current	$	—	$	—	$	811		$	7
Pre-tax accumulated other comprehensive income (loss)	$	206	$	873	$	(1,928	)	$	9,152
Cash collateral included in Derivative liabilities	$	786	$	620	$	—		$	—
Cash collateral included in Other current assets	$	1,078	$	709	$	—		$	—
Expense included in Revenue ^(c)	$	429	$	88	$	(58	)	$	—

________________________


(a)	Crude in Bbls, gas in MMBtu.


(b)	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.


(c)	Represents the amortization of put premiums.

Utilities Group [Member]

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:



	Dec. 31, 2012		Dec. 31, 2011
	Notional (MMBtus)	Maximum Term (months)	Notional (MMBtus)	Maximum Term (months)
Natural gas futures purchased	15,350,000	83	14,310,000	84
Natural gas options purchased	2,430,000	2	1,720,000	3
Natural gas basis swaps purchased	12,020,000	72	7,160,000	60

Schedule of Derivative Instruments, Gain (Loss) [Table Text Block]

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:



	Dec. 31, 2012		Dec. 31, 2011
Derivative assets, current	$	—	$	9,844
Derivative assets, non-current	$	43	$	52
Derivative liabilities, non-current	$	—	$	7,156
Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities	$	9,596	$	17,556

Cash collateral receivable (payable) included in derivatives	$	8,576	$	19,416
Cash collateral included in Other assets, current	$	4,354	$	—
Option premiums and commissions included in derivatives	$	1,063	$	880

Fair Value Measurements Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments, Gain (Loss)

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]



	As of Dec. 31, 2012
	Level 1 ^(a)		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Cash equivalents	15,462		—		—		—			15,462
Total	$	15,462	$	3,703	$	43	$	—		$	19,208

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

______________


(a)	Level 1 assets and liabilities are described in Note 5.

The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)



	As of Dec. 31, 2011
	Level 1 ^(a)		Level 2			Level 3		Cash Collateral and Counterparty Netting		Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	768	$	5	$	773
Basis Swaps -- Oil	—		727			—		—		727
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		9,158			—		—		9,158
Commodity derivatives - Utilities	—		(9,520		)	—		19,416		9,896
Cash equivalents	6,005		—			—		—		6,005
Total	$	6,005	$	365		$	768	$	19,421	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	1,165	$	5	$	1,170
Basis Swaps -- Oil	—		2,200			—		—		2,200
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		7			—		—		7
Commodity derivatives - Utilities	—		7,156			—		—		7,156
Interest rate swaps	—		122,867			—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	133,400

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the changes in level 3 recurring fair value (in thousands):



	As of Dec. 31, 2012									As of Dec. 31, 2011
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities			Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	768		$	—		$	768		$	266
Total gain (loss) included in revenue	—			—			—			—
Total gain (loss) included in AOCI	(360		)	(54		)	(414		)	598
Purchases	—			192			192			—
Issuances	—			—			—			—
Settlements	(4		)	—			(4		)	(96		)
Transfers into level 3^(a)	—			—			—			—
Transfers out of level 3^(b)(c)	(404		)	(95		)	(499		)	—
Balances at end of period	$	—		$	43		$	43		$	768

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)	$	(54	)	$	(101	)



	As of Dec. 31, 2012								As of Dec. 31, 2011
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities		Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	1,165		$	—	$	1,165		$	—
Total gain (loss) included in revenue	—			—		—			—
Total gain (loss) included in AOCI	182			—		182			1,165
Purchases	—					—			—
Issuances	—			—		—			—
Settlements	—			—		—			—
Transfers into level 3^(a)	—			—		—			—
Transfers out of level 3^(b)(c)	(1,347		)	—		(1,347		)	—
Balances at end of period	$	—		$	—	$	—		$	1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	—		$	—

__________


(a)	Transfers into Level 3 would 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.


(b)	Transfers out of Level 3 would 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.


(c)	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

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 Dec. 31 (in thousands):



	2012		2011
Balance, beginning of period	$	7,043	$	6,126
Unrealized gain (loss)	727		917
Balance, end of period	$	7,770	$	7,043

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following tables present the fair value and balance sheet classification of our derivative instruments as of Dec. 31. exclusive of cash collateral (in thousands):



		2012				2011
	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	$	2,874	$	—	$	8,739	$	—
Commodity derivatives	Derivative assets - non-current	510		—		1,919		—
Commodity derivatives	Derivative liabilities - current	—		1,993		—		2,559
Commodity derivatives	Derivative liabilities - non-current	—		821		—		818
Interest rate swaps	Derivative liabilities - current	—		7,038		—		6,513
Interest rate swaps	Derivative liabilities - non-current	—		16,941		—		20,363
Total derivatives designated as hedges		$	3,384	$	26,793	$	10,658	$	30,253

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	362	$	—	$	—	$	9,572
Commodity derivatives	Derivative assets - non-current	—		—		—		(52		)
Commodity derivatives	Derivative liabilities - current	1,180		4,957		—		—
Commodity derivatives	Derivative liabilities - non-current	406		5,153		—		7,156
Interest rate swaps	Derivative liabilities - current	—		94,108		—		75,295
Interest rate swaps	Derivative liabilities - non-current	—		—		—		20,696
Total derivatives not designated as hedges		$	1,948	$	104,218	$	—	$	112,667

Cash Flow Hedging

Derivative Instruments, Gain (Loss)

Schedule of Derivative Instruments, Gain (Loss) [Table Text Block]

The impact of cash flow hedges on our Consolidated Statements of Income and Balance Sheets for the years ended are presented as follows (in thousands):



	Dec. 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(4,794	)	Interest expense	$	(7,607	)		$	—
Commodity derivatives	2,639			Revenue	8,784				—
Total	$	(2,155	)		$	1,177			$	—



	Dec. 31, 2011
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(12,280	)	Interest expense	$	(7,664	)		$	—
Commodity derivatives	7,741			Revenue	5,487				—
Total	$	(4,539	)		$	(2,177	)		$	—



	Dec. 31, 2010
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)			Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)

Interest rate swaps	$	(13,527	)	Interest expense	$	(7,609	)		$	—
Commodity derivatives	15,456			Revenue	14,339				—
Total	$	1,929			$	6,730			$	—

Derivatives Not Designated as Hedge Instruments [Member]

Derivative Instruments, Gain (Loss)

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The impact of derivative instruments that have not been designated as hedging instruments on our Consolidated Statements of Income for the years ended Dec. 31 was as follows (in thousands):



		2012			2011			2010
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	Unrealized gain (loss) on interest rate swap, net	$	1,882		$	(42,010	)	$	(15,193	)
Interest rate swaps - realized	Interest expense	(12,959		)	(13,373		)	(13,312		)
		$	(11,077	)	$	(55,383	)	$	(28,505	)

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income (loss), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Fair value of financial instruments

The estimated fair values of our financial instruments at Dec. 31 were as follows (in thousands):



	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents^(a)	$	15,462	$	15,462	$	21,628	$	21,628
Restricted cash and equivalents ^(a)	$	7,916	$	7,916	$	9,254	$	9,254
Notes payable ^(a)	$	277,000	$	277,000	$	345,000	$	345,000
Long-term debt, including current maturities ^(b)	$	1,042,850	$	1,231,559	$	1,282,882	$	1,464,289

_______________


(a)	Fair value approximates carrying 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)

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13476-108611

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13467-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Table Text Block]

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



Utilities Group	2012			2011			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	$	959,636	45	$	707,498	49	25	80
Electric transmission	234,279		50	170,146		49	40	65
Electric distribution	631,654		44	580,699		45	15	65
Plant acquisition adjustment	4,870		32	4,870		32	32	32
General	137,584		22	136,304		22	3	60
Capital lease - plant in service ^(a)	260,874		19	260,874		20	19	19
Construction work in progress	48,008			288,760
Total electric plant	2,276,905			2,149,151
Less accumulated depreciation and amortization	439,772			385,840
Electric plant net of accumulated depreciation and amortization	$	1,837,133		$	1,763,311

_____________


(a)	Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP.



	2012			2011			Lives (in years)
Gas Utilities	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Property, Plant and Equipment		Weighted Average Useful Life (in years)	Minimum	Maximum

Gas plant:
Production	$	13	37	$	35	37	37	37
Gas transmission	18,071		54	15,543		53	53	57
Gas distribution	474,998		46	442,114		46	41	56
General	68,856		19	56,869		19	16	22
Construction work in progress	6,305			8,813
Total gas plant	568,243			523,374
Less accumulated depreciation and amortization	68,530			52,249
Gas plant net of accumulated depreciation and amortization	$	499,713		$	471,125



2012									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	139,396	$	1,323	$	38,541	$	102,178	35	2	40
Coal Mining	148,045		7,023		80,210		74,858		14	2	59
Oil and Gas	785,594		—		562,926		222,668		24	3	25
	$	1,073,035	$	8,346	$	681,677	$	399,704



2011									Lives ( in years)
Non-regulated Energy	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum

Power Generation	$	135,051	$	930	$	35,074	$	100,907	36	2	40
Coal Mining	140,683		4,341		73,777		71,247		20	2	39
Oil and Gas	763,645		—		386,377		377,268		25	3	26
	$	1,039,379	$	5,271	$	495,228	$	549,422



2012										Lives ( in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization ^(a)			Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	368	$	3,875	$	(1,956	)	$	6,199	6	2	30

___________

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



2011									Lives (in years)
	Property, Plant and Equipment		Construction Work in Progress		Less Accumulated Depreciation, Depletion and Amortization		Net Property, Plant and Equipment		Weighted Average Useful Life	Minimum	Maximum
Corporate	$	2,136	$	4,705	$	1,124	$	5,717	6	2	30

Jointly Owned Facilities Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2012

Jointly Owned Facilities [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

At Dec. 31, 2012, our interests in jointly-owned generating facilities and transmission systems were (in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,465	$	451	$	47,776
Transmission Tie	$	19,648	$	—	$	4,414
Wygen I	$	105,020	$	343	$	25,162
Wygen III	$	130,267	$	565	$	8,376
Busch Ranch Wind Project	$	17,984	$	—	$	150

Long-Term Debt Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

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



	Due Date	Interest Rate	Dec. 31, 2012			Dec. 31, 2011
Corporate
Senior unsecured notes due 2013 ^{(a) (c)}	May 15, 2013	6.50%	$	—		$	225,000
Unamortized discount on notes due 2013			—			(41		)
Senior unsecured notes due 2014^(c)	May 15, 2014	9.00%	250,000			250,000
Senior unsecured notes due 2020 ^(c)	July 15, 2020	5.88%	200,000			200,000
Corporate term loan, variable rate ^(b)	Sept. 30, 2013	1.63%	100,000			100,000
Total Corporate Debt			550,000			774,959

Electric Utilities
First Mortgage Bonds due 2032	Aug. 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	Nov. 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(111		)	(115		)
Pollution control revenue bonds due 2014 ^(d)	Oct. 1, 2014	4.80%	—			6,450
Pollution control revenue bonds due 2024	Oct. 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	Nov. 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(b)	Sept. 1, 2021	0.20%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(b)	March 1, 2027	0.20%	10,000			10,000
Series 94A Debt, variable rate ^(b)	June 1, 2024	1.35%	2,855			2,855
Other long-term debt	May 25, 2012	13.66%	—			72
Total Electric Utilities			396,944			403,462

Power Generation
Black Hills Wyoming project financing, variable rate ^(b)	Dec. 9, 2016	3.59%	95,906			104,461

Total long-term debt			1,042,850			1,282,882
Less current maturities			103,973			2,473
Net long-term debt			$	938,877		$	1,280,409

_______________


(a)	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.


(b)	Variable interest rates; rates presented are as of Dec. 31, 2012.


(c)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.


(d)	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.

Schedule of Maturities of Long-term Debt [Table Text Block]

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



2013	$	103,973
2014	$	256,023
2015	$	6,963
2016	$	78,947
2017	$	—
Thereafter	$	597,055

Deferred Financing Costs [Table Text Block]

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



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Senior unsecured notes due 2014	$	634	$	462	$	462	$	462
Senior unsecured notes due 2020	$	1,260	$	167	$	167	$	77
First mortgage bonds due 2032	$	651	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,037	$	76	$	76	$	76
First mortgage bonds due 2037	$	766	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	3,177	$	1,037	$	1,012	$	1,036
Other	$	721	$	57	$	70	$	74

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Subparagraph (SX 210.5-02.22)
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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
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.4-08.(e),(f))
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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 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 02
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Notes Payable Notes Payable (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Short-term Debt

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



	Dec. 31, 2012				Dec. 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	127,000	$	36,300	$	195,000	$	43,700
Term Loan due June 2013^(a)	150,000		—		150,000		—
Total	$	277,000	$	36,300	$	345,000	$	43,700

Deferred Financing Costs [Table Text Block]

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



	Deferred Financing Costs Remaining in Other Assets, Non-current on Balance Sheet at		Amortization Expense for the years ended Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Senior unsecured notes due 2014	$	634	$	462	$	462	$	462
Senior unsecured notes due 2020	$	1,260	$	167	$	167	$	77
First mortgage bonds due 2032	$	651	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,037	$	76	$	76	$	76
First mortgage bonds due 2037	$	766	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	3,177	$	1,037	$	1,012	$	1,036
Other	$	721	$	57	$	70	$	74

Credit Facility Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):



	At Dec. 31, 2012			Covenant Requirement
Consolidated net worth	$	1,232,509		Greater than	$	924,895
Recourse leverage ratio	53.8		%	Less than	65.0		%

Revolving Credit Facility, Existing [Member]

Deferred Financing Costs [Table Text Block]

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 Dec. 31,
	Dec. 31, 2012		2012		2011		2010
Revolving Credit Facility	$	2,068	$	2,187	$	1,891	$	1,340

Asset Retirement Obligations Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

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):



	Dec. 31, 2011		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)		Dec. 31, 2012
Electric Utilities	$	3,064	$	3,626	$	—		$	291	$	—	$	6,981
Gas Utilities	270		—		(22		)	11		—		259
Coal Mining	17,158		1,627		—			921		580		20,286
Oil and Gas	22,422		158		(1,059		)	1,345		156		23,022
Total	$	42,914	$	5,411	$	(1,081	)	$	2,568	$	736	$	50,548



	Dec. 31, 2010		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates^(a)			Dec. 31, 2011
Electric Utilities	$	3,039	$	—	$	—		$	25	$	—		$	3,064
Gas Utilities	255		—		—			15		—			270
Coal Mining	17,560		—		—			1,123		(1,525		)	17,158
Oil and Gas	21,663		43		(627		)	1,343		—			22,422
Total	$	42,517	$	43	$	(627	)	$	2,506	$	(1,525	)	$	42,914

_____________________


(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

Common Stock Common Stock (Tables)

12 Months Ended

Dec. 31, 2012

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

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]

Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follow (in thousands):



	2012		2011		2010
Stock-based compensation expense	$	8,271	$	5,643	$	5,637

Employee Stock Option [Member]

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

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

A summary of the status of the stock options at Dec. 31, 2012 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	264		$	30.50
Granted	—		—
Forfeited/canceled	(16	)	32.04
Expired	(26	)	34.97
Exercised	(101	)	28.21
Balance at end of period	121		$	31.23	5.7	$	619

Exercisable at end of period	71		$	30.65	3.8	$	404

The table below provides details of our option plans at Dec. 31 (in thousands):



	2012		2011		2010
Summary of Stock Options
Unrecognized compensation expense	$	218	$	479	$	—
Intrinsic value of options exercised^(a)	$	623	$	94	$	234
Net cash received from exercise of options	$	2,839	$	1,009	$	1,034
Tax benefit realized from exercise of shares ^(b)	$	218	$	33	$	82

_____________________


(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 and Restricted Stock Units [Member]

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

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

A summary of the status of the restricted stock and non-vested restricted stock units at Dec. 31, 2012 was as follows:



	Restricted Stock and Stock Units		Weighted-Average Grant Date Fair Value
	(in thousands)
Restricted Stock and Restricted Stock Units balance at beginning of period	278		$	28.82
Granted	151		34.99
Vested	(108	)	27.94
Forfeited	(34	)	30.22
Restricted Stock and Restricted Stock Units balance at end of period	287		$	32.23

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



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2012	$	34.99	$	3,781
2011	$	30.33	$	3,211
2010	$	27.30	$	2,212

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 [Table Text Block]

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



			Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares	Minimum	Maximum
Jan. 1, 2010	Jan. 1, 2010 - Dec. 31, 2012	66	0%	175%
Jan. 1, 2011	Jan. 1, 2011 - Dec. 31, 2013	62	0%	175%
Jan. 1, 2012	Jan. 1, 2012 - Dec. 31, 2014	65	0%	200%

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



	Equity Portion				Liability Portion
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average Dec. 31, 2012 Fair Value
	(in thousands)				(in thousands)
Performance Shares balance at beginning of period	106		$	26.47	106
Granted	33		32.26		33
Forfeited	(7	)	26.19		(7	)
Vested	(36	)	29.20		(36	)
Performance Shares balance at end of period	96		$	27.49	96		$	26.04

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
Dec. 31, 2012	$	32.26
Dec. 31, 2011	$	25.92
Dec. 31, 2010	$	24.26

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



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
Jan. 1, 2009 to Dec. 31, 2011	2012	—	$	—	$	—
Jan. 1, 2008 to Dec. 31, 2010	2011	—	$	—	$	—
Jan. 1, 2007 to Dec. 31, 2009	2010	—	$	—	$	—

DRIP [Member]

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

Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity [Table Text Block]

A summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31, is as follows (shares in thousands):



	2012		2011
Shares Issued	101		103

Weighted Average Price	$	33.58	$	31.23

Unissued Shares Available	353		453

Operating Leases Operating Leases (Tables)

12 Months Ended

Dec. 31, 2012

Leases, Operating [Abstract]

Operating Leases of Lessor Disclosure [Text Block]



	2012		2011		2010
Rent expense	$	6,839	$	6,125	$	4,219

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

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



2013	$	2,690
2014	$	2,377
2015	$	2,144
2016	$	1,465
2017	$	1,269
Thereafter	$	2,811

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Operating Loss Carryforwards [Line Items]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

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



	2012			2011			2010
Current:
Current federal income tax expense (benefit)	$	4,972		$	(14,539	)	$	678
Current state income tax expense (benefit)	3,712			(837		)	4,137
	8,684			(15,376		)	4,815
Deferred:
Deferred federal income tax expense (benefit)	39,876			30,876			20,186
Deferred state income tax expense (benefit)	68			2,970			(2,495		)
Tax credit amortization expense (benefit)	(228		)	(246		)	(337		)
	39,716			33,600			17,354

Total income tax expense (benefit)	$	48,400		$	18,224		$	22,169

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

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



	2012			2011
Deferred tax assets:
Asset valuation reserves	$	3,101		$	2,605
Regulatory liabilities	57,471			40,642
Employee benefits	23,767			22,488
Items of other comprehensive income (loss)	20,038			36,398
Derivative fair value adjustments	35,947			39,099
State net operating loss	8,300			12,311
Federal net operating loss	147,153			195,834
Asset impairment	55,971			47,033
State tax credits	15,546			—
Other deferred tax assets	25,101			17,683
Less: Valuation allowance	(6,192		)	(773		)
Total deferred tax assets	386,203			413,320

Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(571,262		)	(508,261		)
Regulatory assets	(23,537		)	(23,498		)
Mining development and oil exploration	(48,411		)	(94,334		)
Deferred costs	(17,723		)	(15,663		)
State deferred tax liability	(19,986		)	(14,611		)
Other deferred tax liabilities	(13,961		)	(20,739		)
Total deferred tax liabilities	(694,880		)	(677,106		)

Net deferred tax liability	$	(308,677	)	$	(263,786	)

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

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



	2012		2011		2010
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	2.0		1.8		1.1
Amortization of excess deferred and investment tax credits	(0.2	)	(0.5	)	(0.4	)
Percentage depletion in excess of cost	(1.3	)	(2.5	)	(1.7	)
Equity AFUDC	—		(0.5	)	(1.0	)
Tax credits	—		—		(3.2	)
Accounting for uncertain tax positions adjustment	0.8		2.8		1.2
Flow-through adjustments^(a)	(1.3	)	(4.5	)	(4.6	)
Other tax differences	0.4		(0.5	)	(0.4	)
	35.4	%	31.1	%	26.0	%

_________________________

(a)

Summary of Operating Loss Carryforwards [Table Text Block]

At Dec. 31, 2012, we had federal and state NOL carryforwards of $425.8 million and $475.6 million, respectively, which will expire at various dates as follows (in thousands):



Expiration Years	Federal Net Operating Loss Carry forward		State Net Operating Loss Carry forward
2014-2019	$	2,217	$	146,854
2020-2025	$	16,461	$	119,459
2026-2031	$	407,086	$	209,319

Summary of Income Tax Contingencies [Table Text Block]



	Changes in Uncertain Tax Positions
Beginning balance at Jan. 1, 2010	$	107,088
Additions for prior year tax positions	19,592
Reductions for prior year tax positions	(76,545		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2010	50,135
Additions for prior year tax positions	2,725
Reductions for prior year tax positions	(3,533		)
Additions for current year tax positions	—
Settlements	—
Ending balance at Dec. 31, 2011	49,327
Additions for prior year tax positions	111
Reductions for prior year tax positions	(8,906		)
Additions for current year tax positions	151
Settlements	—
Ending balance at Dec. 31, 2012	$	40,683

Interest Expense Income Included In Income Tax Expense Benefit [Table Text Block]

We recognized the following interest expense for the years ended Dec. 31 as follows (in thousands):



	2012		2011		2010
Interest expense included in income tax expense	$	1,400	$	1,400	$	2,300

Foreign Tax Authority [Member]

Operating Loss Carryforwards [Line Items]

Summary of Other Tax Carryforwards [Table Text Block]



Foreign Tax Credit Carryforward, Gross		Expiration Year
$	263	2012
$	6	2013
$	376	2014
$	693	2015
$	5	2016
$	41	2017
$	961	2018

State and Local Jurisdiction [Member]

Operating Loss Carryforwards [Line Items]

Summary of Other Tax Carryforwards [Table Text Block]

State tax credits have been generated and are available to offset future state income taxes. At Dec. 31, 2012, we had the following state tax credit carryforwards (in thousands):



State Tax Credit Carryforwards			Expiration Year
Investment tax credit	$	14,711	2023
Research and development	$	835	No expiration

Comprehensive Income Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2012

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Balances by classification included within Accumulated Other Comprehensive Income (Loss)

Balances by classification included within Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheets were as follows (in thousands):



	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(1,911		)	(699		)	(2,610		)
As of Dec. 31, 2012	$	(15,713	)	$	(19,775	)	$	(35,488	)


	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
As of Dec. 31, 2010 *	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,363		)	(7,934		)	(9,297		)
As of Dec. 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)

____________

* Includes cash flow hedges of equity method investee related to the Idaho Cogeneration Facilities.

Supplemental Cash Flow Information Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information



Years ended Dec. 31,	2012			2011			2010
	(in thousands)
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$	35,556		$	37,529		$	48,879
Increase (decrease) in capitalized assets associated with asset retirement obligations	$	5,743		$	(1,525	)	$	(1,858	)

Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	$	(116,593	)	$	(103,110	)	$	(101,947	)
Income taxes, net	$	(3,027	)	$	9,854		$	9,384

Business Segments Business Segments Information (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting Information, Additional Information [Abstract]

Segment information included in Condensed Consolidated Balance Sheets

Segment information was as follows (in thousands):



Total Assets (net of inter-company eliminations) as of Dec. 31,	2012		2011
Utilities:
Electric ^(a)	$	2,387,458	$	2,254,914
Gas	765,165		746,444
Non-regulated Energy:
Power Generation^(a)	119,170		129,121
Coal Mining	83,810		88,704
Oil and Gas	258,460		425,970
Corporate^(b)	115,408		141,079
Discontinued Operations^(c)	—		340,851
Total assets	$	3,729,471	$	4,127,083

__________________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.


(b)	Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.


(c)	See Note 23 for further information relating to discontinued operations.



Capital Expenditures and Asset Acquisitions^(a) for the years ended Dec. 31,	2012		2011
Utilities:
Electric Utilities	$	167,263	$	173,078
Gas Utilities	45,711		43,954
Non-regulated Energy:
Power Generation	5,547		98,927
Coal Mining	13,420		10,438
Oil and Gas	107,839		89,672
Corporate	7,376		13,279
Total capital expenditures and asset acquisitions of continuing operations	347,156		429,348
Total capital expenditures of discontinued operations	824		2,359
Total capital expenditures and asset acquisitions	$	347,980	$	431,707

_________________


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



Property, Plant and Equipment as of Dec. 31,	2012		2011
Utilities:
Electric Utilities ^(a)	$	2,276,905	$	2,149,151
Gas Utilities	568,243		523,374
Non-regulated Energy:
Power Generation ^(a)	140,719		135,981
Coal Mining	155,068		145,024
Oil and Gas	785,594		763,645
Corporate	4,243		6,841
Total property, plant and equipment	$	3,930,772	$	3,724,016

_______________


(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

Segment information included in Condensed Consolidated Statements of Income



	Consolidating Income Statement
Year ended Dec. 31, 2012	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	610,732		$	454,081		$	4,189		$	25,810		$	79,072		$	—		$	—		$	1,173,884
Inter-company revenue	16,234			—			75,200			31,968			—			196,453			(319,855		)	—
Fuel, purchased power and cost of gas sold	273,474			245,349			—			—			—			—			(111,757		)	407,066
Gross margin	353,492			208,732			79,389			57,778			79,072			196,453			(208,098		)	766,818

Operations and maintenance	146,527			117,390			29,991			42,553			43,267			179,059			(188,051		)	370,736
Gain on sale of operating assets ^(a)	—			—			—			—			(29,129		)	—			—			(29,129		)
Depreciation, depletion and amortization	75,244			25,163			4,599			13,060			38,494			10,936			(12,864		)	154,632
Impairment of long-lived assets^(b)	—			—			—			—			26,868			—			—			26,868
Operating income (loss)	131,721			66,179			44,799			2,165			(428		)	6,458			(7,183		)	243,711

Interest expense ^(c)	(59,194		)	(26,746		)	(15,452		)	(238		)	(4,539		)	(92,650		)	85,209			(113,610		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			1,882			—			1,882
Interest income	8,153			2,765			695			1,168			604			64,695			(76,123		)	1,957
Other income (expense), net	1,182			105			7			2,616			207			48,769			(49,921		)	2,965
Income tax benefit (expense)	(30,264		)	(14,313		)	(8,721		)	(85		)	1,927			3,187			(131		)	(48,400		)
Income (loss) from continuing operations	$	51,598		$	27,990		$	21,328		$	5,626		$	(2,229	)	$	32,341		$	(48,149	)	$	88,505

________________


(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22).


(b)	Oil and Gas includes a ceiling test impairment (see Note 12).


(c)	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8).



	Consolidating Income Statement
Year ended Dec. 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Inter-company revenue	13,396			—			27,613			34,090			—			192,250			(267,349		)	—
Fuel, purchased power and cost of gas sold	310,352			331,961			—			—			—			97			(67,421		)	574,989
Gross margin	303,979			222,623			31,672			66,892			79,808			192,153			(199,928		)	697,199

Operations and maintenance	142,815			121,980			16,538			56,617			41,380			170,947			(174,908		)	375,369
Gain on sale of operating assets ^(a)	(768		)	—			—			—			—			1			767			—
Depreciation, depletion and amortization	52,475			24,307			4,199			18,670			35,690			11,205			(10,955		)	135,591
Operating income (loss)	109,457			76,336			10,935			(8,395		)	2,738			10,000			(14,832		)	186,239

Interest expense	(53,770		)	(31,621		)	(8,903		)	(9		)	(5,896		)	(93,314		)	102,130			(91,383		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(42,010		)	—			(42,010		)
Interest income	14,794			5,645			1,529			3,897			2			64,299			(88,149		)	2,017
Other income (expense), net	481			217			1,094			2,192			(216		)	46,510			(46,552		)	3,726
Income tax benefit (expense)	(23,271		)	(16,408		)	(1,644		)	1,891			1,651			19,289			268			(18,224		)
Income (loss) from continuing operations	$	47,691		$	34,169		$	3,011		$	(424	)	$	(1,721	)	$	4,774		$	(47,135	)	$	40,365

_________________


(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.



	Consolidating Income Statement
Year ended Dec. 31, 2010	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Inter-company Eliminations			Total

Revenue	$	554,617		$	550,707		$	4,297		$	31,285		$	74,164		$	—		$	—		$	1,215,070
Inter-company revenue	15,397			—			26,052			26,557			—			140,756			(204,141		)	4,621
Fuel, purchased power and cost of gas sold	292,811			333,717			—			—			—			150			(59,711		)	566,967
Gross margin	277,203			216,990			30,349			57,842			74,164			140,606			(144,430		)	652,724

Operations and maintenance	136,873			125,447			16,210			34,028			39,299			129,641			(129,879		)	351,619
Gain on sale of operating assets ^(a)	(6,238		)	(2,683		)	—			—			—			—			—			(8,921		)
Depreciation, depletion and amortization	47,276			25,258			4,466			19,083			30,283			9,469			(9,229		)	126,606
Operating income (loss)	99,292			68,968			9,673			4,731			4,582			1,496			(5,322		)	183,420

Interest expense	(43,855		)	(28,927		)	(9,303		)	(177		)	(5,380		)	(75,406		)	72,442			(90,606		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			(15,193		)	—			(15,193		)
Interest income	6,812			1,472			1,193			3,357			8			54,472			(66,773		)	541
Other income (expense), net	3,215			47			854			2,149			722			28,768			(28,607		)	7,148
Income tax benefit (expense)	(18,012		)	(14,449		)	(266		)	(2,379		)	425			12,512			—			(22,169		)
Income (loss) from continuing operations	$	47,452		$	27,111		$	2,151		$	7,681		$	357		$	6,649		$	(28,260	)	$	63,141

______________________


(a)	Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22).

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

Defined Benefit Plan Disclosure [Line Items]

Employee Benefit Plans Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Allocation of Plan Assets [Table Text Block]

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



	2012		2011
Equity	47	%	64	%
Real estate	8		3
Fixed income	44		32
Cash	1		1
Total	100	%	100	%

Schedule of Defined Contribution Plans Contributions [Table Text Block]

Contributions for the years ended Dec. 31 were as follows (in thousands):



	2012		2011
Defined Contribution Plan
Company Retirement Contribution	$	2,639	$	2,440
Matching contributions - Defined Contribution Plans	$	8,981	$	8,916



	2012		2011
Defined Benefit Plans
Defined Benefit Pension Plans	$	25,350	$	11,050
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	5,191	$	4,963
Supplemental Non-Qualified Defined Benefit Plans	$	1,270	$	956

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]



	As of Dec. 31, 2012
	Level 1 ^(a)		Level 2		Level 3		Cash Collateral and Counterparty Netting			Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	378	$	—	$	—		$	378
Basis Swaps -- Oil	—		1,325		—		—			1,325
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		2,000		—		—			2,000
Commodity derivatives - Utilities	—		—		43		—			43
Cash equivalents	15,462		—		—		—			15,462
Total	$	15,462	$	3,703	$	43	$	—		$	19,208

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	1,131	$	—	$	(336	)	$	795
Basis Swaps -- Oil	—		502		—		(450		)	52
Options -- Gas	—		—		—		—			—
Basis Swaps -- Gas	—		1,127		—		(620		)	507
Commodity derivatives - Utilities	—		8,576		—		(8,576		)	—
Interest rate swaps	—		118,088		—		(5,960		)	112,128
Total	$	—	$	129,424	$	—	$	(15,942	)	$	113,482

______________


(a)	Level 1 assets and liabilities are described in Note 5.

The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Commodity derivatives - Utilities ^(a)	$	43	Independent price quotes	Long-term natural gas prices - Basis Differential	$	(0.13	)

_____________

(a)



	As of Dec. 31, 2011
	Level 1 ^(a)		Level 2			Level 3		Cash Collateral and Counterparty Netting		Total
Assets:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	768	$	5	$	773
Basis Swaps -- Oil	—		727			—		—		727
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		9,158			—		—		9,158
Commodity derivatives - Utilities	—		(9,520		)	—		19,416		9,896
Cash equivalents	6,005		—			—		—		6,005
Total	$	6,005	$	365		$	768	$	19,421	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas:
Options -- Oil	$	—	$	—		$	1,165	$	5	$	1,170
Basis Swaps -- Oil	—		2,200			—		—		2,200
Options -- Gas	—		—			—		—		—
Basis Swaps -- Gas	—		7			—		—		7
Commodity derivatives - Utilities	—		7,156			—		—		7,156
Interest rate swaps	—		122,867			—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	133,400

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

The following tables present the changes in level 3 recurring fair value (in thousands):



	As of Dec. 31, 2012									As of Dec. 31, 2011
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities			Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	768		$	—		$	768		$	266
Total gain (loss) included in revenue	—			—			—			—
Total gain (loss) included in AOCI	(360		)	(54		)	(414		)	598
Purchases	—			192			192			—
Issuances	—			—			—			—
Settlements	(4		)	—			(4		)	(96		)
Transfers into level 3^(a)	—			—			—			—
Transfers out of level 3^(b)(c)	(404		)	(95		)	(499		)	—
Balances at end of period	$	—		$	43		$	43		$	768

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	(54	)	$	(54	)	$	(101	)



	As of Dec. 31, 2012								As of Dec. 31, 2011
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Utilities		Total			Commodity Derivatives -- Oil
Balances as of beginning of period	$	1,165		$	—	$	1,165		$	—
Total gain (loss) included in revenue	—			—		—			—
Total gain (loss) included in AOCI	182			—		182			1,165
Purchases	—					—			—
Issuances	—			—		—			—
Settlements	—			—		—			—
Transfers into level 3^(a)	—			—		—			—
Transfers out of level 3^(b)(c)	(1,347		)	—		(1,347		)	—
Balances at end of period	$	—		$	—	$	—		$	1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	—		$	—

__________


(a)	Transfers into Level 3 would 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.


(b)	Transfers out of Level 3 would 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.


(c)	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

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 Dec. 31 (in thousands):



	2012		2011
Balance, beginning of period	$	7,043	$	6,126
Unrealized gain (loss)	727		917
Balance, end of period	$	7,770	$	7,043

Fair Value, Assets Measured on Recurring Basis [Table Text Block]

The following table presents the quantitative information about level 3 fair value measurements (dollars in thousands):



	Fair Value at		Valuation	Unobservable	Range (Weighted)
	Dec. 31, 2012		Technique	Input	Average
Assets:
Common Collective Trust - Real Estate ^(a)	$	7,770	Market Approach	Redemption Restriction	N/A

_____________

(a)

Schedule of Changes in Projected Benefit Obligations [Table Text Block]

Benefit Obligations



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2012			2011			2012			2011			2012			2011
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	325,944		$	280,623		$	30,223		$	24,725		$	50,141		$	46,304
Service cost	5,720			5,421			889			1,028			1,610			1,498
Interest cost	14,747			14,929			1,410			1,298			2,093			2,168
Actuarial (gain) loss	28,639			36,543			3,140			4,128			(4,430		)	3,017
Amendments	—			—			—			—			—			(160		)
Benefits paid	(11,815		)	(11,178		)	(1,269		)	(956		)	(5,190		)	(4,963		)
Plan curtailment liability reduction	—			(394		)	—			—			—			—
Medicare Part D accrued	—			—			—			—			289			188
Plan participants’ contributions	—			—			—			—			2,168			2,089
Projected benefit obligation at end of year	$	363,235		$	325,944		$	34,393		$	30,223		$	46,681		$	50,141

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

A reconciliation of the fair value of Plan assets was as follows (in thousands):



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans ^(a)
	2012			2011			2012		2011		2012			2011
Beginning market value of plan assets	$	221,722		$	220,164		$	—	$	—	$	4,319		$	4,564
Investment income (loss)	33,559			1,686			—		—		(3		)	1
Employer contributions	25,350			11,050			—		—		2,172			2,087
Retiree contributions	—			—			—		—		1,458			1,366
Benefits paid	(11,815		)	(11,178		)	—		—		(3,595		)	(3,713		)
Plan administrative expenses	—			—			—		—		—			14
Ending market value of plan assets	$	268,816		$	221,722		$	—	$	—	$	4,351		$	4,319

____________________


(a)	Asset of VEBA

Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

Amounts recognized in the Consolidated Balance Sheets at Dec. 31 consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Regulatory assets	$	94,199	$	93,423	$	—	$	—	$	6,438	$	9,161
Current liabilities	$	—	$	—	$	1,286	$	1,116	$	2,573	$	3,522
Non-current liabilities	$	94,410	$	104,214	$	33,180	$	30,953	$	39,807	$	42,313
Regulatory liabilities	$	—	$	—	$	—	$	—	$	2,174	$	590

Schedule of Accumulated and Projected Benefit Obligations [Table Text Block]

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012		2011
Accumulated benefit obligation - Black Hills Corporation	$	124,143	$	106,800	$	28,056	$	23,023	$	12,309	$	14,313
Accumulated benefit obligation - Black Hills Energy	202,897		184,345		453		446		25,868		25,842
Accumulated benefit obligation - Cheyenne Light	—		5,731		—		—		8,504		9,986
Total Accumulated Benefit Obligation	$	327,040	$	296,876	$	28,509	$	23,469	$	46,681	$	50,141

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
	2012			2011			2010			2012		2011		2010		2012			2011			2010
Service cost	$	5,720		$	5,421		$	6,131		$	889	$	1,028	$	685	$	1,610		$	1,498		$	1,509
Interest cost	14,747			14,929			15,091			1,410		1,298		1,284		2,093			2,168			2,446
Expected return on assets	(16,334		)	(16,955		)	(14,493		)	—		—		—		(78		)	(164		)	(208		)
Amortization of prior service cost	89			99			99			3		3		3		(500		)	(479		)	(309		)
Recognized net actuarial loss (gain)	9,630			4,540			3,126			807		510		285		887			677			636
Curtailment expense	—			13			57			—		—		—		—			—			—
Net periodic expense	$	13,852		$	8,047		$	10,011		$	3,109	$	2,839	$	2,257	$	4,012		$	3,700		$	4,074

Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]



	Defined Benefit Pension Plans				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plans
	2012		2011		2012		2011		2012			2011
Net (gain) loss	$	12,090	$	11,472	$	7,283	$	6,894	$	2,097		$	2,556
Prior service cost (gain)	78		98		11		12		(1,784		)	(1,956		)
Total accumulated other comprehensive (income) loss	$	12,168	$	11,570	$	7,294	$	6,906	$	313		$	600

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]



	Defined Benefit Pension Plans		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plans
Net loss	$	8,005	$	515	$	313
Prior service cost (credit)	41		2		(325		)
Total net periodic benefit cost expected to be recognized during calendar year 2013	$	8,046	$	517	$	(12	)

Schedule of Assumptions Used [Table Text Block]

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:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate	4.30	%	4.65	%	5.48	%	3.44	%	4.30	%	4.95	%	3.85	%	4.42	%	5.03	%
Rate of increase in compensation levels	3.84	%	3.77	%	3.79	%	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:	2012		2011		2010		2012		2011		2010		2012		2011		2010

Discount rate:
Black Hills Corporation	4.68	%	5.50	%	6.05	%	4.70	%	5.00	%	6.10	%	4.35	%	5.00	%	5.90	%
Black Hills Energy	4.60	%	5.40	%	6.00	%	3.90	%	4.40	%	5.05	%	4.35	%	4.60	%	5.15	%
Cheyenne Light	N/A		5.55	%	6.05	%	N/A		N/A		N/A		4.65	%	5.50	%	6.00	%

Expected long-term rate of return on assets ^(a)	7.25	%	7.75	%	8.00	%	N/A		N/A		N/A		2.00	%	4.00	%	5.00	%
Rate of increase in compensation levels	3.75	%	3.79	%	4.20	%	5.00	%	5.00	%	5.00	%	NA		NA		N/A

_____________________________


(a)	The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 net periodic pension cost.

Schedule of Health Care Cost Trend Rates [Table Text Block]

The healthcare benefit obligation was determined at Dec. 31 as follows:



	Black Hills Corporation		Black Hills Energy		Cheyenne Light
2012
Healthcare trend rate pre-65
Trend for next year	7.75	%	7.75	%	7.75	%
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	6.50	%	6.50	%	6.50	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2026		2026		2026

2011
Healthcare trend rate pre-65
Trend for next year	9.01	%	9.01	%	9.01	%
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	9.01	%	9.01	%	9.01	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year Ultimate Trend Reached	2027		2027		2027

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

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 Dec. 31, 2012 Accumulated Postretirement Benefit Obligation			Impact on 2012 Service and Interest Cost
Increase 1%	$	2,082		$	127
Decrease 1%	$	(1,771	)	$	(107	)

Schedule of Expected Benefit Payments [Table Text Block]

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
2013	$	13,034	$	1,286	$	3,136
2014	$	13,953	$	1,463	$	3,350
2015	$	14,890	$	1,462	$	3,399
2016	$	15,982	$	1,540	$	3,419
2017	$	17,013	$	1,586	$	3,456
2018-2022	$	102,883	$	7,949	$	16,814

Defined Benefit Plan Disclosure [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	1,486	$	—	$	—	$	1,486
Common Collective Trust - Money Market	—		1,118		—		1,118
Common Collective Trust - Equity	—		126,105		—		126,105
Common Collective Trust - Fixed Income	—		114,440		—		114,440
Common Collective Trust - Real Estate	—		13,361		7,770		21,131
Structured Products	—		4,536		—		4,536
Insurance Contracts	—		—		—		—
Total investments measured at fair value	$	1,486	$	259,560	$	7,770	$	268,816



Defined Benefit Pension Plans	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	70	$	—	$	—	$	70
Registered Investment Companies - Equity	23,498		—		—		23,498
Registered Investment Companies - Fixed Income	23,422		—		—		23,422
103-12 Investment Entities - Equity	—		10,329		—		10,329
Common Collective Trust - Money Market	—		25		—		25
Common Collective Trust - Equity	—		103,004		—		103,004
Common Collective Trust - Fixed Income	—		48,024		—		48,024
Common Collective Trust - Real Estate	—		—		7,042		7,042
Structured Products	—		3,884		—		3,884
Insurance Contracts	—		2,424		—		2,424
Total investments measured at fair value	$	46,990	$	167,690	$	7,042	$	221,722

Defined Benefit Postretirement Health Coverage [Member]

Defined Benefit Plan Disclosure [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]



Non-pension Defined Benefit Postretirement Plans	Dec. 31, 2012
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,351	$	—	$	4,351
Total investments measured at fair value	$	—	$	4,351	$	—	$	4,351



Non-pension Defined Benefit Postretirement Plan	Dec. 31, 2011
	Level 1		Level 2		Level 3		Total
Common Collective Trust - Money Market	$	—	$	4,319	$	—	$	4,319
Total investments measured at fair value	$	—	$	4,319	$	—	$	4,319

Commitments and Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment [Table Text Block]

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



	2012		2011		2010
PPA with PacifiCorp	$	13,224	$	12,515	$	12,936
PPA with PSCo^(a)	$	—	$	97,988	$	110,575
Transmission services agreement with PacifiCorp	$	1,215	$	1,215	$	1,215
PPA with Happy Jack	$	1,988	$	1,955	$	2,815
PPA with Silver Sage	$	3,269	$	3,281	$	1,723
Busch Ranch Wind Project	$	502	$	—	$	—

_______________________


(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and gas supply agreements (in thousands):



2013	$	187,301
2014	$	109,707
2015	$	108,024
2016	$	97,972
2017	$	86,564
Thereafter	$	222,002

Tabular disclosure of unconditional purchase obligations that are not recognized as a liability on the balance sheet, including the nature and significant terms of an unconditional purchase obligation; the amount of the fixed and determinable portion of the obligation as of the date of the latest balance sheet presented in the aggregate and, if determinable, for each of the five succeeding fiscal years; the nature of any variable components of the obligation; the amount purchased under the obligation (for example, the take-or-pay or throughput contract) for the reporting period; and may include the amount of imputed interest necessary to reduce the obligation to present value.

Schedule of Guarantor Obligations [Table Text Block]

Guarantees Guarantees (Tables)

12 Months Ended

Dec. 31, 2012

Guarantees [Abstract]

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



	Maximum Exposure at
Nature of Guarantee	Dec. 31, 2012		Expiration
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric⁽²⁾	33,264		March 29, 2013
Indemnification for subsidiary reclamation/surety bonds ⁽³⁾	54,509		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Colorado Gas ⁽⁴⁾	10,000		July 31, 2013
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply ⁽⁵⁾	7,500		June 30, 2013
	$	175,273

_______________________

(1)


(2)	We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.


(3)	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.


(4)	We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.


(5)	We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.

Tabular disclosure of each guarantee obligation, or each group of similar guarantee obligations, including (a) the nature of the guarantee, including its term, how it arose, and the events or circumstances that would require the guarantor to perform under the guarantee; (b) the maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee; (c) the current carrying amount of the liability, if any, for the guarantor's obligations under the guarantee; and (d) the nature of any recourse provisions under the guarantee, and any assets held either as collateral or by third parties, and any relevant related party disclosure. Excludes disclosures about product warranties.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Reserves (Unaudited) Oil and Gas Exploration and Production Industries Disclosure (Tables)

12 Months Ended

Dec. 31, 2012

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]

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



	2012		2011		2010
Acquisition of properties:
Proved	$	2,437	$	673	$	—
Unproved	33,052		8,317		3,846
Exploration costs	115		44,384		8,159
Development costs	73,877		38,638		25,264
Asset retirement obligations incurred	158		43		1,228
Total costs incurred	$	109,639	$	92,055	$	38,497

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]

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



	2012						2011						2010
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	6,223			95,904			5,940			95,456			5,274			87,660
Production ^(a)	(560		)	(8,686		)	(452		)	(8,526		)	(376		)	(8,484		)
Additions - acquisitions (sales)^(b)	(2,025		)	(3,070		)	(84		)	—			(13		)	(377		)
Additions - extensions and discoveries	449			2,898			927			29,664			1,145			1,710
Revisions to previous estimates ^(c)	29			(31,061		)	(108		)	(20,690		)	(90		)	14,947
Balance at end of year	4,116			55,985			6,223			95,904			5,940			95,456

Proved developed reserves at end of year included above	3,851			54,086			4,830			71,867			4,434			67,656

Proved undeveloped reserves at the end of year included in above	265			1,901			1,393			24,037			1,506			27,800

NYMEX prices	$	94.71		$	2.76		$	96.19		$	4.12		$	79.43		$	4.38

Well-head reserve prices	$	85.31		$	2.24		$	88.49		$	3.59		$	70.82		$	3.45

________________________


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


(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.


(c)	Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.

Schedule of Oil and Gas In Process Activities [Table Text Block]

PUD locations, proved reserves and future development costs associated with the Williston Basin during 2012 and at Dec. 31, 2012 were:



	As of Dec. 31, 2012
Williston Basin	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Existed	0.9	3	$	4.9
Added	0.5	8	$	2.1
Williston Basin	1.4	11	$	7.0

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]

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



	2012			2011			2010
Unproved oil and gas properties	$	59,526		$	28,656		$	28,160
Proved oil and gas properties	662,444			674,494			592,978
Gross capitalized costs	721,970			703,150			621,138

Accumulated depreciation, depletion and amortization and valuation allowances ^(a)	(534,777		)	(361,173		)	(334,955		)
Net capitalized costs	$	187,193		$	341,977		$	286,183

__________________


(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]

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



	2012			2011			2010
Revenue	$	79,072		$	79,808		$	74,164

Production costs	23,483			23,820			21,922
Gain on sale of assets	(29,129		)	—			—
Depreciation, depletion and amortization and valuation provisions	37,323			34,415			29,013
Impairment of long-lived assets	26,868			—			—
Total costs	58,545			58,235			50,935
Results of operations from producing activities before tax	20,527			21,573			23,229

Income tax benefit (expense)	(7,082		)	(7,442		)	(8,014		)
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	13,445		$	14,131		$	15,215

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block]

The table below sets forth the cost of unproved properties excluded from the amortization base as of Dec. 31, 2012 and notes the year in which the associated costs were incurred (in thousands):



	2012		2011		2010			Prior		Total
Leasehold acquisition cost	$	35,539	$	638	$	2,138		$	16,709	$	55,024
Exploration cost	328		—		—			—		328
Capitalized interest	683		60		(36		)	3,467		4,174
Total	$	36,550	$	698	$	2,102		$	20,176	$	59,526

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]

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 Dec. 31 (in thousands):



	2012			2011			2010
Future cash inflows	$	502,769		$	931,637		$	764,585
Future production costs	(186,695		)	(280,910		)	(256,455		)
Future development costs	(8,462		)	(92,233		)	(73,805		)
Future income tax expense	(69,877		)	(157,922		)	(111,666		)
Future net cash flows	237,735			400,572			322,659
10 percent annual discount for estimated timing of cash flows	(101,632		)	(197,215		)	(154,551		)
Standardized measure of discounted future net cash flows	$	136,103		$	203,357		$	168,108

Increase Decrease In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures [Table Text Block]

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



	2012			2011			2010
Standardized measure - beginning of year	$	203,357		$	168,108		$	129,108
Sales and transfers of oil and gas produced, net of production costs	(48,905		)	(52,914		)	(40,282		)
Net changes in prices and production costs	(42,639		)	57,087			57,380
Extensions, discoveries and improved recovery, less related costs	19,870			31,179			17,076
Changes in future development costs	43,854			43,809			(17,125		)
Development costs incurred during the period	21,931			18,940			4,975
Revisions of previous quantity estimates	(86,277		)	(58,211		)	27,513
Accretion of discount	25,509			19,655			13,434
Net change in income taxes	36,578			(23,283		)	(23,233		)
Purchases of reserves	—			—			—
Sales of reserves ^(a)	(37,175		)	(1,013		)	(738		)
Standardized measure - end of year	$	136,103		$	203,357		$	168,108

________


(a)	Reflects sale of Williston Basin assets

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
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-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 19
-Paragraph 59S, 59T, 59U, 59V, 59W, 59X
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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.

Cash proceeds from sale of operating assets [Table Text Block]

Sale of Operating Assets Oil and Gas (Tables)

12 Months Ended

Dec. 31, 2012

Net cash proceeds were as follows (in thousands):



Cash proceeds received on date of sale	$	243,314
Less:
Post close adjustments	2,793
Transaction adviser fees	(1,400		)
Estimated payment for contractual obligation related to “back-in” fee *	(16,847		)
Net cash proceeds	$	227,860

_____________


*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Discontinued Operations Condensed Income Statement of Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2012

Condensed Statement of Income [Member]

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

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]



For the Years Ended Dec. 31,	2012			2011			2010

Revenue	$	(604	)	$	41,101		$	27,999

Pre-tax income (loss) from discontinued operations	(6,061		)	14,838			8,673
Pre-tax gain (loss) on sale	(4,184		)	—			—
Income tax (expense) benefit	3,268			(5,473		)	(3,129		)
Income (loss) from discontinued operations, net of tax^(a)	$	(6,977	)	$	9,365		$	5,544

________


(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Condensed Balance Sheet [Member]

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

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

Net assets of the Energy Marketing segment included in Assets/Liabilities of discontinued operations in the Consolidated Balance Sheets were as follows (in thousands) as of:



	Dec. 31, 2011
Other current assets	$	280,221
Derivative assets, current and non-current	52,859
Property, plant and equipment, net	5,828
Goodwill	1,435
Other non-current assets	508
Other current liabilities	(132,951		)
Derivative liabilities, current and non-current	(26,084		)
Other non-current liabilities	(14,894		)
Net assets	$	166,922

Tabular disclosure of disposal groups, which may include the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the classification and carrying value of the assets and liabilities comprising the disposal group, and the segment in which the disposal group was reported. Also may include the amount of adjustments to amounts previously reported in discontinued operations such as resolution of contingencies arising from the disposal transaction or the operations of the component prior to disposal.

Quarterly Financial Information Disclosure [Abstract]

Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Schedule of Quarterly Financial Information [Table Text Block]

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 2012 and 2011.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2012
Revenue	$	365,851		$	242,363		$	246,808		$	318,862
Operating income^(a)	$	70,048		$	20,591		$	77,810		$	75,262
Income (loss) from continuing operations^{(b) (c)}	$	35,271		$	(12,323	)	$	34,623		$	30,934
Income (loss) from discontinued operations	$	(5,484	)	$	(1,160	)	$	(166	)	$	(167	)
Net income (loss) available for common stock ^{(b) (c)}	$	29,787		$	(13,483	)	$	34,457		$	30,767

Income (loss) per share for continuing operations - basic	$	0.81		$	(0.28	)	$	0.79		$	0.70
Income (loss) per share for discontinued operations - basic	(0.13		)	(0.03		)	—			—
Income (loss) per share - basic	$	0.68		$	(0.31	)	$	0.79		$	0.70

Income (loss) per share for continuing operations - diluted	$	0.80		$	(0.28	)	$	0.78		$	0.70
Income (loss) per share for discontinued operations - diluted	(0.12		)	(0.03		)	—			—
Income (loss) per share - diluted	$	0.68		$	(0.31	)	$	0.78		$	0.70

Dividends paid per share	$	0.370		$	0.370		$	0.370		$	0.370

Common stock prices - High	$	35.82		$	34.31		$	36.28		$	37.00
Common stock prices - Low	$	32.18		$	31.32		$	30.29		$	33.51

__________________________


(a)	Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.


(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.


(c)	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.



	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2011
Revenue	$	400,835		$	260,649	$	249,523		$	361,181
Operating income	$	58,367		$	36,160	$	39,572		$	52,140
Income (loss) from continuing operations ^(a)	$	29,068		$	3,706	$	(11,163	)	$	18,754
Income (loss) from discontinued operations	$	(2,158	)	$	4,046	$	638		$	6,839
Net income (loss) available for common stock ^(a)	$	26,910		$	7,752	$	(10,525	)	$	25,593

Earnings (loss) per share for continuing operations - basic	$	0.74		$	0.09	$	(0.29	)	$	0.45
Earnings (loss) per share for discontinued operations - basic	(0.05		)	0.11		0.02			0.16
Earnings (loss) per share - basic	$	0.69		$	0.20	$	(0.27	)	$	0.61

Earnings (loss) per share for continuing operations - diluted	$	0.73		$	0.09	$	(0.29	)	$	0.44
Earnings (loss) per share for discontinued operations - diluted	(0.05		)	0.10		0.02			0.16
Earnings (loss) per share - diluted	$	0.68		$	0.19	$	(0.27	)	$	0.60

Dividends paid per share	$	0.365		$	0.365	$	0.365		$	0.365

Common stock prices - High	$	33.64		$	34.85	$	32.22		$	34.47
Common stock prices - Low	$	29.76		$	28.12	$	25.83		$	29.10

__________________________


(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively

Business Description and Significant Accounting Policies Business Description (Details)	12 Months Ended
	Dec. 31, 2012 Business_Group
Segment Reporting Information [Line Items]
Number of Business Groups	2

Business Description and Significant Accounting Policies Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (768)	$ (1,661)
Accounts receivable, net	163,698	156,774
Electric Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(527)	(545)
Accounts receivable, net	77,798	63,379
Gas Utilities [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(222)	(1,011)
Accounts receivable, net	71,235	77,334
Power Generation [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	16	282
Coal Mining [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,247	4,056
Oil and Gas [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(19)	(105)
Accounts receivable, net	11,603	11,177
Corporate [Member]
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	799	546
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	100,661	98,292
Billed Revenues [Member] \| Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	54,482	42,773
Billed Revenues [Member] \| Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	31,495	39,353
Billed Revenues [Member] \| Power Generation [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	16	282
Billed Revenues [Member] \| Coal Mining [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,247	4,056
Billed Revenues [Member] \| Oil and Gas [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	11,622	11,282
Billed Revenues [Member] \| Corporate [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	799	546
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	63,805	60,143
Unbilled Revenues [Member] \| Electric Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	23,843	21,151
Unbilled Revenues [Member] \| Gas Utilities [Member]
Accounts Receivable [Line Items]
Accounts Receivable, Trade	39,962	38,992
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
Unbilled Revenues [Member] \| Corporate [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, 2012	Dec. 31, 2011
Materials and supplies	$ 43,397	$ 40,838
Total materials, supplies and fuel	77,643	84,064
Electric Utilities [Member]
Fuel - Electric Utilities	8,589	8,201
Gas Utilities [Member]
Natural gas in storage held for distribution	$ 25,657	$ 35,025

Business Description and Significant Accounting Policies Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 353,396	$ 353,396
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	$ 353,396	353,396
Electric Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	72.00%
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 250,487	250,487
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	$ 250,487	250,487
Gas Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	28.00%
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 94,144	94,144
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	94,144	94,144
Power Generation [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765	8,765
Goodwill, Additions (adjustments)	0	0
Goodwill, Ending Balance	$ 8,765	$ 8,765

Carrying amount as of the balance sheet date, which is the cumulative amount paid and (if applicable) the fair value of any noncontrolling interest in the acquiree, adjusted for any amortization recognized prior to the adoption of any changes in generally accepted accounting principles (as applicable) and for any impairment charges, in excess of the fair value of net assets acquired in one or more business combination transactions.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=14024403&loc=d3e13816-109267

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6388280&loc=d3e13770-109266

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 43
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 72
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 142
-Paragraph 45
-Subparagraph e
-Clause 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph l
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Finite-Lived Intangible Assets [Line Items]

Business Description and Significant Accounting Policies Schedule of Intangible Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Finite-Lived Intangible Assets, Useful Life, Maximum (years)

20 years

Finite-Lived Intangible Assets [Roll Forward]

Intangible assets, net, beginning balance

$ 3,843

$ 4,069

$ 4,309

Intangible asset, additions (adjustments)

Intangible assets, amortization expense

^[1]

(223)

(226)

(240)

Intangible assets, net, ending balance

3,620

$ 3,843

$ 4,069

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 2013, 2014, 2015, 2016, and 2017.

Business Description and Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Schedule of Regulatory Assets and Liabilities [line items]

$ 219,393

$ 242,130

Deferred energy, fuel and gas cost adjustments [Member]

$ 141,284

124,448

Schedule of Regulatory Assets and Liabilities [line items]

P1Y

Employee benefit plans [Member]

^[1]

$ 21,091

16,961

Schedule of Regulatory Assets and Liabilities [line items]

P13Y

Schedule of Regulatory Assets and Liabilities [line items]

^[2]

$ 59,362

59,455

Cost of removal [Member]

P44Y

Other regulatory liabilities [Member]

^[1]

$ 53,526

42,257

Schedule of Regulatory Assets and Liabilities [line items]

P25Y

Deferred energy, fuel and gas cost adjustments [Member]

^[3]

$ 7,305

5,775

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P1Y

Deferred gas cost adjustments and gas price derivatives [Member]

^[1]

$ 16,005

33,526

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P7Y

Allowance for Cost of Equity Funds Used During Construction [Member]

^[1]

$ 20,741

26,208

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P45Y

Employee benefit plans [Member]

$ 12,416

^[4]

12,482

^[1]

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P13Y

Schedule of Regulatory Assets and Liabilities [line items]

^[5]

$ 115,521

120,708

Environmental [Member]

Regulatory assets maximum recovery settlement period

subject to approval

Asset retirement obligations [Member]

^[1]

$ 1,792

1,770

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P44Y

Bond issuance costs [Member]

^[1]

$ 3,247

3,097

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P25Y

Renewable energy standard adjustment [Member]

^[1]

$ 3,561

3,704

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P5Y

Flow through accounting [Member]

^[1]

$ 19,484

20,095

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P35Y

Other regulatory assets [Member]

^[6]

$ 16,620

12,191

Schedule of Regulatory Assets and Liabilities [line items]

Regulatory assets maximum recovery settlement period

P15Y

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Employee benefit plans [Member]

^[1]

$ 10,006

$ 8,349

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Other regulatory liabilities [Member]

^[2]

13,200

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Employee benefit plans [Member]

^[3]

2,600

Schedule of Regulatory Assets and Liabilities [line items]

Recovery Plus Rate of Return or Reduction to Rate Base, Regulatory Assets [Domain] | Flow through accounting [Member]

^[5]

24,600

Schedule of Regulatory Assets and Liabilities [line items]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

^[6]

$ 5,400

[1]	Recovery of costs, but not allowed a rate of return.
[2]	Approximately $13.2 million is included in our rate base calculations as a reduction to rate base.
[3]	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.
[4]	In addition to recovery of costs, we are allowed a rate of return.
[5]	In addition to recovery of costs, we are allowed a return on approximately $24.6 million.
[6]	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.

Business Description and Significant Accounting Policies Earnings per Share (Details) - USD ($)
shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

^[1],[2]

Sep. 30, 2012

^[1],[2]

Jun. 30, 2012

^[1],[2]

Mar. 31, 2012

^[1]

Dec. 31, 2011

^[3]

Sep. 30, 2011

^[3]

Jun. 30, 2011

^[3]

Mar. 31, 2011

^[3]

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Weighted average shares - basic

$ 30,934

$ 34,623

$ (12,323)

$ 35,271

$ 18,754

$ (11,163)

$ 3,706

$ 29,068

$ 88,505

$ 40,365

$ 63,141

43,820

39,864

38,916

Dilutive effect of:

Stock Options, shares

Restricted stock, shares

173

153

107

Forward equity instrument, shares

^[4]

Other diluted effects, shares

Weighted average shares - diluted

44,073

40,081

39,091

[1]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
[2]	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.
[3]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.
[4]	In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7655603&loc=d3e1448-109256

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Weighted-Average Number of Common Shares Outstanding
-URI http://asc.fasb.org/extlink&oid=6528421

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Business Description and Significant Accounting Policies Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	163	141	160
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	95	105	158
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	53	17	1
Other Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Anti-dilutive Shares Excluded from Computation of Earnings Per Share, Shares Amount	15	19	1

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Contingent Stock Agreement
-URI http://asc.fasb.org/extlink&oid=6508534

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 13, 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Recently Adopted and Recently Issued Accounting Standards and Legislation Oil and Gas Reserves Calculation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2010 USD ($)
Oil and Gas [Member] \| Accounting Standards Update 2010-03 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement, Effect of Change on Operating Results	$ 1.3

Risk Management Activities Risk Management Activities (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

bbl

MMBTU

Dec. 31, 2011

USD ($)

bbl

MMBTU

Credit Exposure, Non-investment Grade Company

$ 7,600

3,236

$ 18,583

510

1,971

96,541

84,367

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

16,941

49,033

9,844

Cash collateral receivable (payable) included in Derivatives

7,156

8,576

19,416

Cash Collateral, Derivative, Included in Other Assets

4,354

Net Unrealized Gain (Loss) Included in Regulatory assets or Regulatory liabilities

9,596

17,556

Option premium and commissions included in derivatives

1,063

880

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

2,100

Oil and Gas [Member] | Crude Oil [Member]

Cash collateral receivable (payable) included in Derivatives

786

Cash Collateral, Derivative, Included in Other Assets

1,078

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

Cash collateral receivable (payable) included in Derivatives

620

Cash Collateral, Derivative, Included in Other Assets

$ 709

$ 0

Designated as Hedging Instrument [Member]

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

4 years

5 years

$ 7,039

$ 6,513

Pre-tax accumulated other comprehensive income (loss)

16,941

20,363

(23,980)

(26,876)

Cash collateral receivable (payable) included in Derivatives

^[1]

$ 150,000

Pre-tax gain (loss) included in Consolidated Statement of Income

5.04%

$ 0

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

7,000

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

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Dedesignated Interest Rate Swap Expiring 2018 [Member]

$ 75,000

75,000

^[2]

6 years

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Dedesignated Interest Rate Swaps Expiring 2028 [Member]

$ 100,000

^[2]

16 years

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Credit Risk [Member]

$ 150,000

Potential Future Exposure on Credit Related Contingent Feature

50,000

20,000

91,617

78,502

Potential Future Exposure on Credit Related Contingent Feature

9,252

31,368

1,000

Black Hills Corporation [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

3,469

3,207

Pre-tax accumulated other comprehensive income (loss)

9,252

10,672

(12,721)

(13,879)

Cash Collateral, Derivative, Included in Other Assets

$ 0

4 years

5 years

^[1]

$ 75,000

Pre-tax gain (loss) included in Consolidated Statement of Income

4.97%

$ 0

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

3,500

Black Hills Corporation [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

88,148

75,295

Pre-tax accumulated other comprehensive income (loss)

20,696

Cash collateral receivable (payable) included in Derivatives

$ 5,960

$ 0

1 year

2 years

^[1],[2]

$ 250,000

Pre-tax gain (loss) included in Consolidated Statement of Income

5.67%

$ 1,882

$ (42,010)

Swaps and Options [Member] | Oil and Gas [Member] | Crude Oil [Member]

Derivative notional amount, commodities | bbl

^[3]

528,000

MaximumTerm Hedged in Cash Flow Hedge

^[4]

1 year

1 year 3 months

$ 1,405

$ 729

297

771

847

2,559

Pre-tax accumulated other comprehensive income (loss)

811

206

(1,928)

Expense included in Revenue

^[5]

$ 429

$ (58)

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

MaximumTerm Hedged in Cash Flow Hedge

^[3]

8,215,500

5,406,250

^[4]

9 months

1 year 9 months

$ 1,831

$ 8,010

170

1,148

507

Pre-tax accumulated other comprehensive income (loss)

873

9,152

Expense included in Revenue

^[5]

$ 88

$ 0

Future [Member] | Purchase Contract [Member] | Utilities Group [Member] | Natural Gas for Distribution [Member]

15,350,000

14,310,000

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

83 months

84 months

2,430,000

1,720,000

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

2 months

3 months

12,020,000

7,160,000

Fair Value, Transfers Between Level 1 and Level 2, Description and Policy [Abstract]

72 months

60 months

[1]	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.
[2]	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.
[3]	Crude in Bbls, gas in MMBtu.
[4]	Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.
[5]	Represents the amortization of put premiums.

Fair Value Measurements Fair Value Measurements (Details) - USD ($)

Dec. 31, 2012

Dec. 31, 2011

Fair Value, Assets, Level 1 to Level 2 Transfers, Amount

$ 0

Fair Value, Assets, Level 2 to Level 1 Transfers, Amount

Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount

Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[1]

15,462,000

6,005,000

15,462,000

6,005,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

3,703,000

365,000

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

129,424,000

132,230,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

43,000

768,000

Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member]

1,165,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

19,421,000

Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(15,942,000)

5,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

15,462,000

6,005,000

19,208,000

26,559,000

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

113,482,000

133,400,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

118,088,000

122,867,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(5,960,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

112,128,000

122,867,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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]

378,000

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

1,131,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

768,000

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

1,165,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

5,000

Crude Oil [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(336,000)

5,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

378,000

773,000

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

795,000

1,170,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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]

1,325,000

727,000

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

502,000

2,200,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Crude Oil [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(450,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

1,325,000

727,000

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil and Gas [Member]

52,000

2,200,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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]

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]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Commodity Option [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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]

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]

2,000,000

9,158,000

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil and Gas [Member]

1,127,000

7,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Oil and Gas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas [Member] | Basis Swap [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Oil and Gas [Member]

(620,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

2,000,000

9,158,000

Natural Gas for Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Utilities Group [Member]

507,000

7,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Natural Gas for 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]

(9,520,000)

Natural Gas for Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Utilities Group [Member]

8,576,000

7,156,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

43,000

^[2]

Basis Differential

(0.13)

Natural Gas for Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral and Counterparty Netting [Member] | Utilities Group [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

19,416,000

Natural Gas for Distribution [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member] | Utilities Group [Member]

(8,576,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

43,000

9,896,000

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation RollForward [Roll Forward]

$ 0

$ 7,156,000

[1]

Level 1 assets and liabilities are described in Note 5

[2]

Fair Value Measurements Fair Value Measurements Changes in Level 3 Recurring Fair Value (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

$ 768

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)

(414)

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

192

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(4)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[2]

(499)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

$ 768

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

1,165

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Other Comprehensive Income (Loss)

182

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Purchases

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements

Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

^[2]

(1,347)

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end, assets

(54)

Changes in unrealized gains (losses) relating to instruments still held as of period-end, liabilities

Oil and Gas [Member] | Crude Oil [Member]

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation RollForward [Roll Forward]

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

768

266

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)

(360)

598

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(4)

(96)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[2]

(404)

^[3]

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

768

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

1,165

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Other Comprehensive Income (Loss)

182

1,165

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Purchases

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements

Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

^[2]

(1,347)

^[3]

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

1,165

Changes in unrealized gains (losses) relating to instruments still held as of period-end, assets

(101)

Changes in unrealized gains (losses) relating to instruments still held as of period-end, liabilities

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

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation RollForward [Roll Forward]

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)

(54)

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

192

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[2]

(95)

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Other Comprehensive Income (Loss)

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Purchases

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issues

Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements

Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

^[1]

Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

^[2]

Unobservable Inputs Reconciliations, Recurring Basis, Liability Value

$ 0

Changes in unrealized gains (losses) relating to instruments still held as of period-end, assets

(54)

Changes in unrealized gains (losses) relating to instruments still held as of period-end, liabilities

$ 0

[1]	Transfers into Level 3 would 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.
[2]	Transfers out of Level 3 would 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.
[3]	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

Fair Value Measurements Fair Value Measurements Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 3,384	$ 10,658
Derivative Liability, Fair Value, Net	26,793	30,253
Derivatives Not Designated as Hedge Instruments [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	1,948	0
Derivative Liability, Fair Value, Net	104,218	112,667
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	2,874	8,739
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	510	1,919
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	1,993	2,559
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	821	818
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	362	0
Derivative Asset, Fair Value, Gross Liability	0	9,572
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	(52)
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	1,180	0
Derivative Liability, Fair Value, Gross Liability	4,957	0
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	406	0
Derivative Liability, Fair Value, Gross Liability	5,153	7,156
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	7,038	6,513
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	16,941	20,363
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	94,108	75,295
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	$ 20,696

Fair Value Measurements Fair Value Measurements Hedging Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	$ (11,077)	$ (55,383)	$ (28,505)
Cash Flow Hedging
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(2,155)	(4,539)	1,929
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	1,177	(2,177)	6,730
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0
Cash Flow Hedging \| Interest Rate Swap [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(4,794)	(12,280)	(13,527)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0
Cash Flow Hedging \| Interest Rate Swap [Member] \| Interest Expense
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	(7,607)	(7,664)	(7,609)
Cash Flow Hedging \| Commodity derivatives [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	2,639	7,741	15,456
Cash Flow Hedging \| Commodity derivatives [Member] \| Sales Revenue, Goods, Net [Member]
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	8,784	5,487	14,339
Cash Flow Hedging \| Commodity derivatives [Member] \| Revenue
Summary of Cash Flow Hedge Activity [Abstract]
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0	0
Derivatives Not Designated as Hedge Instruments [Member] \| Interest Rate Swap [Member] \| Interest Expense
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Amount of Gain/(Loss) on Derivatives Recognized in Income	(12,959)	(13,373)	(13,312)
Derivatives Not Designated as Hedge Instruments [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	$ 1,882	$ (42,010)	$ (15,193)

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Restricted cash, at carrying value

$ 15,462

$ 21,628

7,916

9,254

Notes payable, at carrying value

277,000

345,000

Long-term debt, including current maturities at carrying value

1,042,850

1,282,882

Carrying Amount

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Restricted cash, at carrying value

15,462

21,628

7,916

9,254

Notes payable, at carrying value

277,000

345,000

Long-term debt, including current maturities at carrying value

1,042,850

1,282,882

Fair Value

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Cash and cash equivalents, at fair value

^[1]

15,462

21,628

Restricted Cash, at fair value

^[1]

7,916

9,254

Notes payable, fair value

^[1]

277,000

345,000

Long-term debt, including current maturities, at fair value

^[2]

$ 1,231,559

$ 1,464,289

[1]

Fair value approximates carrying 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]

Property, Plant and Equipment Property, Plant and Equipment (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Accumulated depreciation, depletion and amortization

$ 3,930,772

$ 3,724,016

(1,188,023)

(934,441)

2,742,749

2,789,575

Accumulated depreciation, depletion and amortization

^[1]

2,276,905

2,149,151

(439,772)

(385,840)

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

1,837,133

1,763,311

Electric Utilities [Member] | Electric transmission [Member]

959,636

707,498

Electric Utilities [Member] | Electric distribution [Member]

234,279

170,146

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

631,654

580,699

Electric Utilities [Member] | General [Member]

4,870

Electric Utilities [Member] | Assets Held under Capital Leases [Member]

137,584

136,304

Electric Utilities [Member] | Construction work in progress [Member]

^[2]

260,874

48,008

288,760

Accumulated depreciation, depletion and amortization

568,243

523,374

(68,530)

(52,249)

Gas Utilities [Member] | General [Member]

499,713

471,125

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

68,856

56,869

Gas Utilities [Member] | Gas transmission [Member]

Gas Utilities [Member] | Gas distribution [Member]

18,071

15,543

Gas Utilities [Member] | Construction work in progress [Member]

474,998

442,114

Non Regulated Energy Group [Member]

6,305

8,813

1,073,035

1,039,379

Accumulated depreciation, depletion and amortization

8,346

5,271

(681,677)

(495,228)

399,704

549,422

139,396

135,051

1,323

930

Accumulated depreciation, depletion and amortization

^[1]

140,719

135,981

(38,541)

(35,074)

102,178

100,907

148,045

140,683

7,023

4,341

Accumulated depreciation, depletion and amortization

155,068

145,024

(80,210)

(73,777)

74,858

71,247

785,594

763,645

Accumulated depreciation, depletion and amortization

785,594

763,645

(562,926)

(386,377)

222,668

377,268

368

2,136

3,875

4,705

Accumulated depreciation, depletion and amortization

4,243

6,841

1,956

^[3]

(1,124)

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

$ 6,199

$ 5,717

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

45 years

49 years

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

50 years

49 years

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

44 years

45 years

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

32 years

Weighted Average [Member] | Electric Utilities [Member] | Assets Held under Capital Leases [Member]

22 years

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

19 years

20 years

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

19 years

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

37 years

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

54 years

53 years

Weighted Average [Member] | Power Generation [Member]

46 years

Weighted Average [Member] | Coal Mining [Member]

35 years

36 years

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

14 years

20 years

Weighted Average [Member] | Corporate [Member]

24 years

25 years

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

6 years

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

25 years

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

40 years

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

15 years

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

32 years

Minimum [Member] | Electric Utilities [Member] | Assets Held under Capital Leases [Member]

3 years

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

19 years

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

16 years

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

37 years

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

53 years

Minimum [Member] | Power Generation [Member]

41 years

Minimum [Member] | Coal Mining [Member]

2 years

Minimum [Member] | Oil and Gas [Member]

2 years

Minimum [Member] | Corporate [Member]

3 years

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

2 years

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

80 years

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

65 years

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

65 years

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

32 years

Maximum [Member] | Electric Utilities [Member] | Assets Held under Capital Leases [Member]

60 years

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

19 years

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

22 years

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

37 years

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

57 years

Maximum [Member] | Power Generation [Member]

56 years

Maximum [Member] | Coal Mining [Member]

40 years

Maximum [Member] | Oil and Gas [Member]

59 years

39 years

Maximum [Member] | Corporate [Member]

25 years

26 years

30 years

[1]	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.
[2]	Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP.
[3]	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Colorado IPP.

Jointly Owned Facilities Jointly Owned Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2010
Oil and Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	44.70%
Jointly Owned Utility Plant, Net Ownership Amount	$ 4,400
Electric Utilities [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
Electric Utilities [Member] \| Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	20.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 109,465
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	451
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 47,776
Electric Utilities [Member] \| Transmission Tie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	35.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 19,648
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 4,414
Electric Utilities [Member] \| Wygen I I I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	52.00%	23.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 130,267
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	565
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	8,376
Electric Utilities [Member] \| Busch Ranch Wind Farm [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	17,984
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 150
Power Generation [Member] \| Wygen I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	76.50%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 105,020
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	343
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 25,162

Long-Term Debt Long-Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Oct. 31, 2012

Dec. 31, 2011

Long-term Debt, including current maturirities

$ 1,042,850

$ 1,282,882

Long-term Debt, Current Maturities

(103,973)

(2,473)

$ 938,877

1,280,409

Bonds Due 2024 [Member]

Power Generation [Member] | Project Financing Debt Due 2016 [Member]

Jun. 01, 2024

Dec. 09, 2016

^[1]

3.59%

^[1]

$ 95,906

104,461

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

$ 396,944

403,462

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

$ (111)

(115)

Electric Utilities [Member] | Polution Control Revenue Bonds Due 2014 [Member]

Oct. 01, 2014

4.80%

Electric Utilities [Member] | Polution Control Revenue Bonds Due 2024 [Member]

$ 0

^[2]

6,450

Oct. 01, 2024

5.35%

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

$ 12,200

12,200

Nov. 20, 2037

6.67%

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

$ 110,000

110,000

Sep. 01, 2021

^[1]

0.20%

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

^[1]

$ 7,000

7,000

Mar. 01, 2027

^[1]

0.20%

Electric Utilities [Member] | Bonds Due 2024 [Member]

^[1]

$ 10,000

10,000

^[1]

1.35%

Electric Utilities [Member] | Long-term Debt [Member]

^[1]

$ 2,855

2,855

May 25, 2012

13.66%

$ 0

Long-term Debt, Current Maturities

^[3]

550,000

774,959

(100,000)

Potential Future Exposure on Credit Related Contingent Feature

450,000

774,959

$ 1,000

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2013 [Member]

May 15, 2013

6.50%

Debt Instrument, Unamortized Discount

^[3]

$ 0

^[4]

$ 225,000

$ 0

(41)

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2014 [Member]

May 15, 2014

9.00%

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

^[3]

$ 250,000

^[5]

250,000

Jul. 15, 2020

5.88%

Black Hills Corporation [Member] | Corporate Term Loan due September 2013 [Member]

^[3],[6]

$ 200,000

200,000

Sep. 30, 2013

^[1]

1.63%

Senior Unsecured Notes Due 2013 [Member]

^[1]

$ 100,000

[1]	Variable interest rates; rates presented are as of Dec. 31, 2012.
[2]	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.
[3]	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
[4]	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.
[5]	This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.
[6]	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.

Long-Term Debt Aggregate Maturities of Long Term Debt (Details) $ in Thousands	Dec. 31, 2012 USD ($)
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 103,973
Long-term Debt, Maturities, Repayments of Principal in Year Two	256,023
Long-term Debt, Maturities, Repayments of Principal in Year Three	6,963
Long-term Debt, Maturities, Repayments of Principal in Year Four	78,947
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	$ 597,055

Long-Term Debt Long-term Debt Repayment (Details) - USD ($)
$ in Thousands

12 Months Ended

Oct. 31, 2012

May 15, 2012

Dec. 31, 2012

Dec. 31, 2011

Early Repayment of Senior Debt

$ 238,800

Interest Expense, Prepayment of Debt

7,100

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2013 [Member]

^[1]

$ 550,000

$ 774,959

^[1]

$ 225,000

$ 0

^[2]

6.50%

Debt Instrument, Early Repayment Date

May 15, 2013

Oct. 31, 2012

Electric Utilities [Member] | Polution Control Revenue Bonds Due 2014 [Member]

$ 396,944

403,462

$ 0

^[3]

$ 6,450

4.80%

Debt Instrument, Early Repayment Date

Oct. 01, 2014

May 15, 2012

Early Repayment of Subordinated Debt

$ 6,500

[1]	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
[2]	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.
[3]	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.

Long-Term Debt Debt Issuance and Extensions (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

LIBOR [Member] | Corporate Term Loan due September 2013 [Member]

Debt Instrument, Interest Rate Terms

1.375%

Long-term Debt, Variable Interest Rate at Period End

1.63%

Black Hills Corporation [Member] | Corporate Term Loan due September 2013 [Member]

^[1]

$ 550,000

$ 774,959

Long-term Debt, Variable Interest Rate at Period End

^[2]

$ 100,000

^[2]

1.63%

[1]	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
[2]	Variable interest rates; rates presented are as of Dec. 31, 2012.

Long-Term Debt Deferred Financing Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Senior Unsecured Notes Due 2014 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$ 634
Amortization Expense for Deferred Financing Costs	462	$ 462	$ 462
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,260
Amortization Expense for Deferred Financing Costs	167	167	77
First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	651
Amortization Expense for Deferred Financing Costs	33	33	33
First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,037
Amortization Expense for Deferred Financing Costs	76	76	76
First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	766
Amortization Expense for Deferred Financing Costs	31	31	31
Project Financing Debt Due 2016 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	3,177
Amortization Expense for Deferred Financing Costs	1,037	1,012	1,036
Deferred Financing Costs, Other [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	721
Amortization Expense for Deferred Financing Costs	$ 57	$ 70	$ 74

Notes Payable Notes Payable (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Letters of Credit Outstanding, Amount

$ 277,000

$ 345,000

$ 36,300

43,700

Line of Credit Facility, Expiration Date

Feb. 01, 2017

Debt Covenants Disclosure [Abstract]

Consolidated Net Worth, Actual

$ 1,232,509

1,209,336

$ 1,100,270

$ 1,084,837

Line of Credit [Member]

Deferred Finance Costs [Abstract]

Write off of Deferred Debt Issuance Cost

1,500

Debt Covenants Disclosure [Abstract]

Consolidated Net Worth, Actual

1,232,509

Line of Credit, Covenant Requirement, Consolidated Net Worth, Minimum

$ 924,895

Line of Credit Covenant Requirement, Recourse Leverage Ratio, Actual

53.80%

Line of Credit, Covenant Requirement, Recourse Leverage Ratio

65.00%

Line of Credit [Member] | Base Rate Option [Member]

Line of Credit Facility, Interest Rate at Period End

0.50%

Line of Credit [Member] | Eurodollar Option [Member]

Line of Credit Facility, Interest Rate at Period End

1.50%

Line of Credit [Member] | Letter of Credit [Member]

Line of Credit Facility, Interest Rate at Period End

1.50%

Line of Credit [Member] | Revolving Credit Facility, Existing [Member]

Letters of Credit Outstanding, Amount

$ 127,000

195,000

36,300

43,700

Line of Credit Facility, Current Borrowing Capacity

500,000

Line of Credit Facility, Maximum Borrowing Capacity

$ 750,000

Line of Credit Facility, Commitment Fee Percentage

0.25%

Deferred Finance Costs [Abstract]

Deferred Finance Costs, Noncurrent, Gross

$ 2,800

Deferred Finance Costs, Noncurrent, Net

2,068

Amortization Expense for Deferred Financing Costs

2,187

1,891

$ 1,340

Loans Payable [Member] | Corporate Term Loan due June 2013 [Member]

Letters of Credit Outstanding, Amount

150,000

^[1]

150,000

$ 0

[1]	In June 2012, this short-term loan was extended for one year. See discussion below.

Notes Payable Notes Payable Corporate Term Loan (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Short-term Debt [Line Items]

Loans Payable [Member] | Corporate Term Loan due June 2013 [Member]

$ 277,000

$ 345,000

Short-term Debt [Line Items]

$ 150,000

^[1]

$ 150,000

Debt Instrument, Interest Rate Terms

Jun. 24, 2013

1.10%

Loans Payable [Member] | Corporate Term Loan due June 2013 [Member] | LIBOR [Member]

Short-term Debt [Line Items]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

1.35%

[1]	In June 2012, this short-term loan was extended for one year. See discussion below.

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

$ 42,914

$ 42,517

5,411

(1,081)

(627)

Asset Retirement Obligation, Revision of Prior Estimate

2,568

2,506

^[1]

736

(1,525)

50,548

42,914

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

3,064

3,039

3,626

Asset Retirement Obligation, Revision of Prior Estimate

291

^[1]

6,981

3,064

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

270

255

(22)

Asset Retirement Obligation, Revision of Prior Estimate

^[1]

259

270

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

17,158

17,560

1,627

Asset Retirement Obligation, Revision of Prior Estimate

921

1,123

^[1]

580

(1,525)

20,286

17,158

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

22,422

21,663

158

(1,059)

(627)

Asset Retirement Obligation, Revision of Prior Estimate

1,345

1,343

^[1]

156

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

$ 23,022

$ 22,422

[1]	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

Common Stock Common Stock Equity Issuance (Details) - USD ($) $ in Thousands			12 Months Ended
	Nov. 01, 2011	Nov. 10, 2010	Dec. 31, 2011
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Value, New Issues			$ 119,630
Black Hills Corporation [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Equity Forward Settlement Date			Nov. 01, 2011
Stock Issued During Period, Value, New Issues	$ 119,600
Black Hills Corporation [Member] \| Forward Equity Agreement Over Allotment Shares [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Equity Issuance OverAllotment Shares		413,519
Black Hills Corporation [Member] \| Forward Equity Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares		4,000,000
Common Stock [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Shares, New Issues			4,413,519
Stock Issued During Period, Value, New Issues			$ 4,414
Common Stock [Member] \| Black Hills Corporation [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Shares, New Issues	4,413,519

Common Stock Equity Compensation Plans Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity Compensation Plans, Number of Shares Available for Grant	863,929
Equity Compensation, Nonvested Awards, Unrecognized Compensation Expense	$ 7,800
Employee Share-based Compensation, Nonvested Awards, Weighted Average Period for Recognition (in years)	1 year 11 months
Stock-based compensation expense	$ 8,271	$ 5,643	$ 5,637

Common Stock Stock Option Activity (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 7,800

Employee Share-based Compensation, Nonvested Awards, Weighted Average Period for Recognition (in years)

1 year 11 months

Employee Stock Option [Member]

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

Share-based Compensation Award, Award Vesting Period

3 years

Share-based Compensation Award, Stock Option Award Effective Term

10 years

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

Share-based Compensation Award, Options, Outstanding, Shares, Beginning of Period

264

Share-based Compensation, Options, Grants in Period

Share-based Compensation Award, Options, Forfeitures/canceled in Period

(16)

Share-based Compensation Award, Options, Expired in Period

(26)

Share-based Compensation Award, Options, Exercised in Period

(101)

Share-based Compensation Award, Options, Outstanding, Shares, End of Period

121

264

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable at end of period, Shares

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

Share-based Compensation Award, Options, Outstanding, Weighted Average Exercise Price, Period Start

$ 30.50

Share-based Compensation Award, Options, Grants in Period, Weighted Average Exercise Price

0.00

Share-based Compensation Award, Options, Forfeitures in Period, Weighted Average Exercise Price

32.04

Share-based Compensation Award, Options, Expirations in Period, Weighted Average Exercise Price

34.97

Share-based Compensation Award, Options, Exercises in Period, Weighted Average Exercise Price

28.21

Share-based Compensation Award, Options, Outstanding, Weighted Average Exercise Price, Period End

31.23

$ 30.50

Share-based Compensation Award, Options, Exercisable, Weighted Average Exercise Price

$ 30.65

Share-based Compensation Award, Options, Exercisable, Weighted Average Remaining Contractual Term

5 years 8 months 9 days

Share-based Compensation Arrangement by Share-based Payment Award, Options, Aggregate Intrinsic Value

$ 619

Share-based Compensation, Stock Options, Exercisable at End of Period, Weighted Average Remaining Contractual Term

3 years 9 months 23 days

Share-based Compensation Award, Options, Exercisable at End of Period, Aggregate Intrinsic Value

$ 404

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

218

$ 479

$ 0

Stock Options, Options, Total Intrinsic Value of Options Exercised

^[1]

623

234

Stock Options, Net Cash Received from Exercise of Stock Options

2,839

1,009

1,034

Stock Options, Tax Benefit Realized from Exercise of Stock Options

^[2]

$ 218

$ 33

$ 82

Employee Share-based Compensation, Nonvested Awards, Weighted Average Period for Recognition (in years)

1 year 5 months

[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.

Common Stock Restricted Stock and Restricted Stock Units (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Restrcited Stock Units, Weighted Average Price [Roll Forward]
Equity Compensation, Nonvested Awards, Unrecognized Compensation Expense	$ 7,800
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 11 months
Restricted Stock and Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Share-based Compensation Award, Restricted Stock and Restricted Stock Units, Nonvested, Number, Beginning of Period	278
Restricted Stock and RSUs, Granted in Period, Shares	151
Restricted Stock and RSUs, Vested in Period, Shares	(108)
Restricted Stock and RSUs, Forfeited in Period, Shares	(34)
Share-based Compensation Award, Restricted Stock and Restricted Stock Units, Nonvested, Number, End of Period	287	278
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Restrcited Stock Units, Weighted Average Price [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 28.82
Restricted Stock and RSUs, Granted in Period, Weighted Average Grant Date Fair Value	34.99	$ 30.33	$ 27.30
Restricted Stock and RSUs, Vested in Period, Weighted Average Grant Date Fair Value	27.94
Restricted Stock or RSUs, Forfeitures and Expirations in Period, Weighted Average Exercise Price	30.22
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 32.23	$ 28.82
Restricted Stock and RSUs, Vested in Period, Total Fair Value	$ 3,781	$ 3,211	$ 2,212
Equity Compensation, Nonvested Awards, Unrecognized Compensation Expense	$ 5,200
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	2 years

Common Stock Performance Shares (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,800
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 11 months
Performance Shares, Equity Portion [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	106
Performance Shares, Granted in Period	33
Performance Shares, Forfeited in Period	(7)
Performance Shares, Vested in Period	(36)
Performance Shares, Number of Shares Authorized, End of Period	96	106
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 26.47
Share-based Compensation Award, Equity Instruments Other than Options, Granted in Period, Weighted Average Grant Date Fair Value	32.26
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Forfeited in Period, Weighted Average Grant Date Fair Value	26.19
Peformance Shares, Vested in Period, Weighted Average Grant Date Fair Value	29.20
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 27.49	$ 26.47
Performance Shares, Liability Portion [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	106
Performance Shares, Granted in Period	33
Performance Shares, Forfeited in Period	(7)
Performance Shares, Vested in Period	(36)
Performance Shares, Number of Shares Authorized, End of Period	96	106
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Granted in Period, Weighted Average Grant Date Fair Value	$ 26.04
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Performance Share Award, Payout, Change Of Control	100.00%
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1,700
Performance Share Award, Percentage of Target	170.75%
Employee Service Share-based Compensation, Other Than Options, Total Payout Value	$ 4,500
Performance Shares, Fair Value Assumptions, Weighted Average Volatility Rate	21.00%	30.00%	31.00%
Performance Shares Expected Volatility, Historical Cost	50.00%
Performance Shares Expected Volatility, Implied Cost	50.00%
Peer Percentile	0.78
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	62	66
Performance Shares, Number of Shares Authorized, End of Period	65	62	66
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 25.92	$ 24.26
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 32.26	$ 25.92	$ 24.26
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	0	0	0
Performance Shares, Total Share-based Liabilities Paid	$ 0	$ 0	$ 0
Performance Shares, Vested in Period, Total Intrinsic Value	0	$ 0	$ 0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Share-based Awards Other than Options	$ 2,400
Share-based Compensation, Nonvested Awards, Compensation Not Yet Recognized, Weighted Average Period for Recognition (in years)	1 year 8 months
Minimum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%	0.00%	0.00%
Maximum [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%	175.00%	175.00%
Current Year [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Award Requisite Service Period	3 years
Prior Year [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Award Requisite Service Period		3 years
More Than Two Years Prior [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Award Requisite Service Period			3 years
More Than Three Years Prior [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Award Requisite Service Period				3 years

Common Stock Dividend Reinvestment and Stock Purchase Plan (Details) - DRIP [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock Purchase Percentage of Recent Average Market Price	100.00%
Stock Issued During Period, Shares, Dividend Reinvestment Plan	101	103
Dividend Reinvestment Plan, Weighted Average Price	$ 33.58	$ 31.23
Dividend Reinvestment Plan, Unissued Shares Available	353	453

Common Stock Dividend Restrictions Subsidiaries (Details) $ in Millions	Dec. 31, 2012 USD ($)
Utilities Group [Member]
Restricted Net Assets for Subsidiaries	$ 263.1
Non Regulated Energy Group [Member]
Restricted Net Assets for Subsidiaries	$ 100.0

Impairment of Long-Lived Assets Impairment of Long-Lived Assets (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Jun. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

$ / bbl

$ / MMcf

Dec. 31, 2011

USD ($)

$ / bbl

$ / MMcf

Dec. 31, 2010

USD ($)

$ / bbl

$ / MMcf

Impaired Long-Lived Assets Held and Used [Line Items]

Impairment of long-lived assets | $

$ 26,900

$ 26,868

^[1]

$ 0

Natural Gas Price Per MCF, NYMEX | $ / MMcf

2.76

4.12

4.38

Natural Gas Price Per MCF, Wellhead | $ / MMcf

2.24

3.59

3.45

Crude Oil Price, per Barrel, NYMEX | $ / bbl

94.71

96.19

79.43

Crude Oil Price Per Barrel, Wellhead | $ / bbl

85.31

88.49

70.82

Oil and Gas Properties [Member]

Impaired Long-Lived Assets Held and Used [Line Items]

Natural Gas Price Per MCF, NYMEX | $ / MMcf

3.15

Natural Gas Price Per MCF, Wellhead | $ / MMcf

2.66

Crude Oil Price, per Barrel, NYMEX | $ / bbl

95.67

Crude Oil Price Per Barrel, Wellhead | $ / bbl

85.36

[1]	Oil and Gas includes a ceiling test impairment (see Note 12).

Operating Leases Operating Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Leases, Rent Expense, Net [Abstract]
Operating Leases, Rent Expense	$ 6,839	$ 6,125	$ 4,219
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Current	2,690
Operating Leases, Future Minimum Payments, Due in Two Years	2,377
Operating Leases, Future Minimum Payments, Due in Three Years	2,144
Operating Leases, Future Minimum Payments, Due in Four Years	1,465
Operating Leases, Future Minimum Payments, Due in Five Years	1,269
Operating Leases, Future Minimum Payments, Due Thereafter	$ 2,811

Income Taxes Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Income Tax Expense (Benefit)	$ 4,972	$ (14,539)	$ 678
Current State Income Tax Expense (Benefit)	3,712	(837)	4,137
Current Income Tax Expense (Benefit)	8,684	(15,376)	4,815
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	39,876	30,876	20,186
Deferred State Income Tax Expense (Benefit)	68	2,970	(2,495)
Tax Credit Amortization Expense (Benefit)	(228)	(246)	(337)
Deferred Income Tax Expense (Benefit)	39,716	33,600	17,354
Total Income Tax Expense (Benefit)	$ 48,400	$ 18,224	$ 22,169

Income Taxes Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Asset Valuation Reserve	$ 3,101	$ 2,605
Deferred Tax Assets, Regulatory Assets and Liabilities	57,471	40,642
Deferred Tax Assets, Employee Benefits	23,767	22,488
Deferred Tax Assets, Other Comprehensive (Loss)	20,038	36,398
Deferred Tax Assets, Derivative Fair Value Adjustments	35,947	39,099
Deferred Tax Assets Non-current, State Net Operating Loss	8,300	12,311
Deferred Tax Asset, Non-current, Federal Net Operating Loss	147,153	195,834
Deferred Tax Assets, Non-current, Asset Impairment	55,971	47,033
Deferred Tax Assets, State Tax Credits	15,546	0
Deferred Tax Assets, Other	25,101	17,683
Deferred Tax Assets, Valuation Allowance	(6,192)	(773)
Deferred Tax Assets, Net of Valuation Allowance	386,203	413,320
Deferred Tax Liabilities, Net [Abstract]
Deferred Tax Liabilities Non-current, Accelerated Depreciation, Amortization and Other Plant-Related Differences	(571,262)	(508,261)
Deferred Tax Liabilities Non-current, Regulatory Assets	(23,537)	(23,498)
Deferred Tax Liabilities, Development Operations	(48,411)	(94,334)
Deferred Tax Liabilities, Deferred Costs	(17,723)	(15,663)
Deferred Tax Liability Non-current, State Deferred Tax Liability	(19,986)	(14,611)
Deferred Tax Liabilities, Other Current	(13,961)	(20,739)
Deferred Tax Liabilities, Gross	(694,880)	(677,106)
Net Deferred Tax Assets (Liabilities)	$ 308,677	$ 263,786

Income Taxes Effective Tax Rate Differences From Statutory Tax Rates (Details)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Effective Tax Rate Reconciliation [Line Items]

Federal Statutory Rate

35.00%

State Income Tax (net of federal tax effect)

2.00%

1.80%

1.10%

Amortization Of Excess Deferred and Investment Tax Credits

(0.20%)

(0.50%)

(0.40%)

Percentage Depletion In Excess of Cost

(1.30%)

(2.50%)

(1.70%)

Equity AFUDC

0.00%

(0.50%)

(1.00%)

Tax Credits

0.00%

(3.20%)

Accounting for Uncertain Tax Positions Adjustment

0.80%

2.80%

1.20%

Flow Through Adjustments

^[1]

(1.30%)

(4.50%)

(4.60%)

Other Tax Differences

0.40%

(0.50%)

(0.40%)

Effective Income Tax Rate, Continuing Operations

35.40%

31.10%

26.00%

[1]

Income Taxes Net Operating Loss Carryforwards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($)
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 425,800
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 475,600
NOL Years, Within Seven Years [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2014-2019
NOL Years, Within Seven Years [Member] \| Net Operating Loss Carryforward [Member] \| Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 2,217
NOL Years, Within Seven Years [Member] \| Net Operating Loss Carryforward [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 146,854
NOL Years Eight through Thirteen [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2020-2025
NOL Years Eight through Thirteen [Member] \| Net Operating Loss Carryforward [Member] \| Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 16,461
NOL Years Eight through Thirteen [Member] \| Net Operating Loss Carryforward [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 119,459
NOL Years, Fourteen Through Nineteen [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2026-2031
NOL Years, Fourteen Through Nineteen [Member] \| Net Operating Loss Carryforward [Member] \| Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 407,086
NOL Years, Fourteen Through Nineteen [Member] \| Net Operating Loss Carryforward [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	209,319
Valuation Allowance, Operating Loss Carryforwards [Member] \| State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Valuation Allowance	2,200
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 1,400

Income Taxes Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 49,327	$ 50,135	$ 107,088
Unrecognized Tax Benefits, Increases Resulting from Additions for Prior Period Tax Positions	111	2,725	19,592
Unrecognized Tax Benefits, Decreases Resulting from Reductions for Prior Period Tax Positions	(8,906)	(3,533)	(76,545)
Unrecognized Tax Benefits, Increases Resulting from Additions for Current Year Tax Positions	151	0	0
Unrecognized Tax Benefits, Increases Decreases Resulting from Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	40,683	$ 49,327	$ 50,135
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 1,500

Income Taxes Interest, Penalties and Audits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Interest Expense in Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense Included in Income Tax Expense	$ 1,400	$ 1,400	$ 2,300
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	8,300	6,900
Deferred Income Tax Expense (Benefit)	39,716	$ 33,600	$ 17,354
Like-Kind Exchange [Member]
Interest Expense in Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)	$ 125,000
Internal Revenue Service (IRS) [Member] \| Minimum [Member]
Interest Expense in Income Tax Examination [Line Items]
Income Tax Examination, Year(s) under Examination	2007
Internal Revenue Service (IRS) [Member] \| Maximum [Member]
Interest Expense in Income Tax Examination [Line Items]
Income Tax Examination, Year(s) under Examination	2009
State and Local Jurisdiction [Member] \| Minimum [Member]
Interest Expense in Income Tax Examination [Line Items]
Income Tax Examination, Year(s) under Examination	2001
State and Local Jurisdiction [Member] \| Maximum [Member]
Interest Expense in Income Tax Examination [Line Items]
Income Tax Examination, Year(s) under Examination	2009
Foreign Tax Authority [Member] \| Minimum [Member]
Interest Expense in Income Tax Examination [Line Items]
Income Tax Examination, Year(s) under Examination	1999

Income Taxes Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 15,546	$ 0
Other Tax Carryforward, Gross Amount	2,300
Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	1,800
Tax Credit Carryforward, Valuation Allowance	500
Investment Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 14,711
Tax Credit Carryforward, Expiration Date	Dec. 31, 2023
Research Tax Credit Carryforward [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 835
State Tax Credit [Member] \| State and Local Jurisdiction [Member]
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	3,400
Tax Credit Expiration, Less Than One Year [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 263
Tax Credit Carryforward, Expiration Date	Dec. 31, 2012
Tax Credit Expiration, More Than One Year Within Two Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 6
Tax Credit Carryforward, Expiration Date	Dec. 31, 2013
Tax Credit Expiration, More Than Two Years Within Three Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 376
Tax Credit Carryforward, Expiration Date	Dec. 31, 2014
Tax Credit Expiration, More Than Three Years Within Four Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 693
Tax Credit Carryforward, Expiration Date	Dec. 31, 2015
Tax Credit Expiration, More Than Four Years Within Five Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 5
Tax Credit Carryforward, Expiration Date	Dec. 31, 2016
Tax Credit Expiration, More Than Five Years Within Six Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 41
Tax Credit Carryforward, Expiration Date	Dec. 31, 2017
Tax Credit Expiration, More Than Six Years Within Seven Years of Balance Sheet [Member] \| Foreign Tax Credit Carryforward [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 961
Tax Credit Carryforward, Expiration Date	Dec. 31, 2018

Comprehensive Income Comprehensive Income (Loss) Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Accumulated Other Comprehensive Income (Loss) [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start

$ (32,878)

$ (23,581)

Other Comprehensive Income (Loss), Net of Tax

(2,610)

(9,297)

$ (4,417)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End

(35,488)

(32,878)

(23,581)

Cash Flow Hedging [Member]

Accumulated Other Comprehensive Income (Loss) [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start

(13,802)

(12,439)

^[1]

Other Comprehensive Income (Loss), Net of Tax

(1,911)

(1,363)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End

(15,713)

(13,802)

(12,439)

^[1]

Accumulated Defined Benefit Plans Adjustment [Member]

Accumulated Other Comprehensive Income (Loss) [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start

(19,076)

(11,142)

Other Comprehensive Income (Loss), Net of Tax

(699)

(7,934)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End

$ (19,775)

$ (19,076)

$ (11,142)

[1]	Includes cash flow hedges of equity method investee related to the Idaho Cogeneration Facilities.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e637-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e681-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14A
-URI http://asc.fasb.org/extlink&oid=20435746&loc=SL7669686-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 31
-Article 5

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14, 17, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, plant and equipment acquired with accrued liabilities	$ 35,556	$ 37,529	$ 48,879
Increase (Decrease) in Capitalized Asset Retirement Costs Associated with Asset Retirement Obligations	5,743	(1,525)	(1,858)
Interest (net of amounts capitalized)	(116,593)	(103,110)	(101,947)
Income Taxes Paid, Net	$ (3,027)	$ 9,854	$ 9,384

Business Segments Segment Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Energy Marketing [Member]

$ 3,729,471

$ 4,127,083

340,851

^[1]

^[2]

2,387,458

2,254,914

765,165

746,444

^[2]

119,170

129,121

83,810

88,704

258,460

425,970

$ 115,408

$ 141,079

^[1]

[1]	Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.
[2]	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

Business Segments Capital Expenditures and Asset Acquisitions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Energy Marketing [Member]

^[1]

$ 347,980

$ 431,707

^[1]

824

2,359

^[1]

167,263

173,078

^[1]

45,711

43,954

^[1]

5,547

98,927

^[1]

13,420

10,438

^[1]

107,839

89,672

Total Capital Expenditures and Asset Acquistions, Continuing Operations [Member]

^[1]

7,376

13,279

^[1]

$ 347,156

$ 429,348

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

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

Dec. 31, 2012

Dec. 31, 2011

$ 3,930,772

$ 3,724,016

^[1]

2,276,905

2,149,151

568,243

523,374

^[1]

140,719

135,981

155,068

145,024

785,594

763,645

$ 4,243

$ 6,841

[1]

The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

Business Segments Information Relating to Segments Statement of Income (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

$ 1,173,884

$ 1,272,188

$ 1,215,070

4,621

407,066

574,989

566,967

766,818

697,199

652,724

370,736

375,369

351,619

(29,129)

^[1]

^[2]

(8,921)

^[3]

154,632

135,591

126,606

$ 26,900

26,868

^[4]

$ 75,262

^[5]

$ 77,810

^[5]

20,591

^[5]

$ 70,048

$ 52,140

$ 39,572

$ 36,160

$ 58,367

243,711

186,239

183,420

(113,610)

^[6]

(91,383)

(90,606)

1,882

(42,010)

(15,193)

1,957

2,017

541

2,965

3,726

7,148

(48,400)

(18,224)

(22,169)

$ 30,934

^[7],[8]

$ 34,623

^[7],[8]

$ (12,323)

^[7],[8]

$ 35,271

^[7]

$ 18,754

^[9]

$ (11,163)

^[9]

$ 3,706

^[9]

$ 29,068

^[9]

88,505

40,365

63,141

610,732

600,935

554,617

16,234

13,396

15,397

273,474

310,352

292,811

353,492

303,979

277,203

146,527

142,815

136,873

(768)

^[2]

(6,238)

^[3]

75,244

52,475

47,276

131,721

109,457

99,292

(59,194)

(53,770)

(43,855)

8,153

14,794

6,812

1,182

481

3,215

(30,264)

(23,271)

(18,012)

51,598

47,691

47,452

454,081

554,584

550,707

245,349

331,961

333,717

208,732

222,623

216,990

117,390

121,980

125,447

(2,683)

^[3]

25,163

24,307

25,258

66,179

76,336

68,968

(26,746)

(31,621)

(28,927)

2,765

5,645

1,472

105

217

(14,313)

(16,408)

(14,449)

27,990

34,169

27,111

4,189

4,059

4,297

75,200

27,613

26,052

79,389

31,672

30,349

29,991

16,538

16,210

4,599

4,199

4,466

44,799

10,935

9,673

(15,452)

(8,903)

(9,303)

695

1,529

1,193

1,094

854

(8,721)

(1,644)

(266)

21,328

3,011

2,151

25,810

32,802

31,285

31,968

34,090

26,557

57,778

66,892

57,842

42,553

56,617

34,028

13,060

18,670

19,083

2,165

(8,395)

4,731

(238)

(9)

(177)

1,168

3,897

3,357

2,616

2,192

2,149

(85)

1,891

(2,379)

5,626

(424)

7,681

79,072

79,808

74,164

79,072

79,808

74,164

43,267

41,380

39,299

(29,129)

^[1]

38,494

35,690

30,283

^[4]

26,868

(428)

2,738

4,582

(4,539)

(5,896)

(5,380)

604

207

(216)

722

1,927

1,651

425

Corporate, Without Eliminations [Member]

(2,229)

(1,721)

357

196,453

192,250

140,756

150

196,453

192,153

140,606

179,059

170,947

129,641

10,936

11,205

9,469

6,458

10,000

1,496

(92,650)

^[6]

(93,314)

(75,406)

1,882

(42,010)

(15,193)

64,695

64,299

54,472

48,769

46,510

28,768

3,187

19,289

12,512

Intercompany Elimination [Member]

32,341

4,774

6,649

(319,855)

(267,349)

(204,141)

(111,757)

(67,421)

(59,711)

(208,098)

(199,928)

(144,430)

(188,051)

(174,908)

(129,879)

767

^[2]

(12,864)

(10,955)

(9,229)

(7,183)

(14,832)

(5,322)

85,209

102,130

72,442

(76,123)

(88,149)

(66,773)

(49,921)

(46,552)

(28,607)

(131)

268

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

$ (48,149)

$ (47,135)

$ (28,260)

[1]	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22).
[2]	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.
[3]	Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22).
[4]	Oil and Gas includes a ceiling test impairment (see Note 12).
[5]	(a)Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.
[6]	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8).
[7]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
[8]	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.
[9]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.

Employee Benefit Plans Narrative (Details) $ in Millions	12 Months Ended
Employee Benefit Plans Narrative (Details) $ in Millions	Dec. 31, 2012 USD ($)
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	50.00%
Defined Contribution Plan, Employee Vesting Period	5 years
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Measurement Date	December 31
Not Full Vested [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20.00%
Fully Vested [Member]
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	100.00%
Pension Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (94.4)
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	(34.4)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan, Funded Status of Plan	$ (42.3)
Cheyenne Light [Member]
Pension and Other Postretirement Defined Benefit Plans, Liabilities [Abstract]
Defined Benefit Plan Curtailment Effective Date	Jan. 01, 2012

Employee Benefit Plans Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.25%	8.75%
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	47.00%	64.00%
Real Estate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	8.00%	3.00%
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	44.00%	32.00%
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%	1.00%

Employee Benefit Plans Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	$ 25,350	$ 11,050
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	8,800
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	5,191	4,963
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	1,270	956
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	2,639	2,440
Defined Contribution Plan, 401K [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 8,981	$ 8,916

Employee Benefit Plans Changes in Level 3 Assets Measured at Fair Value on a Recurring Basis, Employee Benefits (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

$ 768

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

$ 768

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

Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]

268,816

221,722

$ 220,164

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

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start

7,043

6,126

Unrealized Gain Loss, Level 3, Defined Benefit Assets

727

917

Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End

7,770

7,043

Real Estate Funds [Member] | Pension Plans, Defined Benefit [Member]

7,770

7,042

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

Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans, Defined Benefit [Member]

21,131

7,042

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

$ 7,770

^[1]

$ 7,042

[1]

Assets, usually stocks, bonds, and other investments, that have been segregated and restricted (usually in a trust) to provide benefits, at their fair value as of the measurement date. Plan assets include amounts contributed by the employer (and by employees for a contributory plan) and amounts earned from investing the contributions, less benefits paid. If a plan has liabilities other than for benefits, those non-benefit obligations may be considered as reductions of plan assets.

Employee Benefit Plans Changes in Benefit Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	$ 325,944	$ 280,623
Service Cost	5,720	5,421	$ 6,131
Interest Cost	14,747	14,929	15,091
Actuarial (Gain) Loss	28,639	36,543
Plan Amendments	0	0
Benefits Paid	(11,815)	(11,178)
Plan Curtailment Reduction	0	(394)
Medicare Part D Accrued	0	0
Plan Participants' Contributions	0	0
Projected Benefit Obligation at End of Year	363,235	325,944	280,623
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	30,223	24,725
Service Cost	889	1,028
Interest Cost	1,410	1,298
Actuarial (Gain) Loss	3,140	4,128
Plan Amendments	0	0
Benefits Paid	(1,269)	(956)
Plan Curtailment Reduction	0	0
Medicare Part D Accrued	0	0
Plan Participants' Contributions	0	0
Projected Benefit Obligation at End of Year	34,393	30,223	24,725
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected Benefit Obligation at Beginning of Year	50,141	46,304
Service Cost	1,610	1,498	1,509
Interest Cost	2,093	2,168	2,446
Actuarial (Gain) Loss	(4,430)	3,017
Plan Amendments	0	(160)
Benefits Paid	(5,190)	(4,963)
Plan Curtailment Reduction	0	0
Medicare Part D Accrued	289	188
Plan Participants' Contributions	2,168	2,089
Projected Benefit Obligation at End of Year	$ 46,681	$ 50,141	$ 46,304

Employee Benefit Plans Changes in Plan Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

$ 221,722

$ 220,164

Investment income (loss)

33,559

1,686

Employer Contributions

25,350

11,050

Plan Administrative Expenses

(11,815)

(11,178)

Supplemental Employee Retirement Plans, Defined Benefit [Member]

268,816

221,722

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Other Postretirement Benefit Plans, Defined Benefit [Member]

(1,269)

(956)

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

4,319

(2,168)

(2,089)

(5,190)

(4,963)

Defined Benefit Plan VEBA [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

4,351

4,319

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

^[1]

4,319

4,564

Investment income (loss)

^[1]

(3)

Employer Contributions

^[1]

2,172

2,087

^[1]

1,458

1,366

Plan Administrative Expenses

^[1]

(3,595)

(3,713)

^[1]

Unfunded Benefit Plan [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

^[1]

4,351

4,319

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Investment income (loss)

Employer Contributions

Plan Administrative Expenses

$ 0

[1]	Asset of VEBA

Employee Benefit Plans Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	$ 219,393	$ 242,130
Non-current Liabilities, Defined Benefit Plans	167,397	177,480
Regulatory Liabilities, Defined Benefit Plans	141,284	124,448
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	94,199	93,423
Current Liabilities, Defined Benefit Plans	0	0
Non-current Liabilities, Defined Benefit Plans	94,410	104,214
Regulatory Liabilities, Defined Benefit Plans	0	0
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	0	0
Current Liabilities, Defined Benefit Plans	1,286	1,116
Non-current Liabilities, Defined Benefit Plans	33,180	30,953
Regulatory Liabilities, Defined Benefit Plans	0	0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	6,438	9,161
Current Liabilities, Defined Benefit Plans	2,573	3,522
Non-current Liabilities, Defined Benefit Plans	39,807	42,313
Regulatory Liabilities, Defined Benefit Plans	$ 2,174	$ 590

This represents the noncurrent liability for underfunded plans recognized in the balance sheet that is associated with the defined benefit pension plans and other postretirement defined benefit plans.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2417-114920

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=21915240&loc=d3e1703-114919

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e2410-114920

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 210.5-02.24)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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

Employee Benefit Plans Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 327,040	$ 296,876
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	28,509	23,469
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	46,681	50,141
Parent Company [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	124,143	106,800
Parent Company [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	28,056	23,023
Parent Company [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	12,309	14,313
Black Hills Energy [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	202,897	184,345
Black Hills Energy [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	453	446
Black Hills Energy [Member] \| Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	25,868	25,842
Cheyenne Light [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	0	5,731
Cheyenne Light [Member] \| Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, 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]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 8,504	$ 9,986

Employee Benefit Plans Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 5,720	$ 5,421	$ 6,131
Interest Cost	14,747	14,929	15,091
Expected return on plan assets	(16,334)	(16,955)	(14,493)
Amortization of prior service cost	89	99	99
Recognition of net actuarial loss (gain)	9,630	4,540	3,126
Curtailment Expense	0	13	57
Net periodic benefit expense	13,852	8,047	10,011
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	889	1,028	685
Interest Cost	1,410	1,298	1,284
Expected return on plan assets	0	0	0
Amortization of prior service cost	3	3	3
Recognition of net actuarial loss (gain)	807	510	285
Curtailment Expense	0	0	0
Net periodic benefit expense	3,109	2,839	2,257
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,610	1,498	1,509
Interest Cost	2,093	2,168	2,446
Expected return on plan assets	(78)	(164)	(208)
Amortization of prior service cost	(500)	(479)	(309)
Recognition of net actuarial loss (gain)	887	677	636
Curtailment Expense	0	0	0
Net periodic benefit expense	$ 4,012	$ 3,700	$ 4,074

Employee Benefit Plans Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	$ 12,090	$ 11,472
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	78	98
Accumulated Other Comprehensive Income (Loss), Net of Tax	12,168	11,570
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	8,005
Prior Service Cost (Credit)	41
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	8,046
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	7,283	6,894
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	11	12
Accumulated Other Comprehensive Income (Loss), Net of Tax	7,294	6,906
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	515
Prior Service Cost (Credit)	2
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	517
Other Postretirement Benefit Plans, Defined Benefit [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Abstract]
Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	2,097	2,556
Accumulated Other Comprehensive Income Prior Service Cost (Gain), After Tax	(1,784)	(1,956)
Accumulated Other Comprehensive Income (Loss), Net of Tax	313	$ 600
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	313
Prior Service Cost (Credit)	(325)
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	$ (12)

Employee Benefit Plans Defined Benefit Plans Assumptions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]

7.25%

8.75%

Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation

$ 2,082

Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation

(1,771)

Effect of One Percentage Point Increase on Service and Interest Cost Components

127

Effect of One Percentage Point Decrease on Service and Interest Cost Components

$ (107)

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Assumptions, Rate of Increase in Compensation Levels

4.30%

4.65%

5.48%

3.84%

3.77%

3.79%

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

Assumptions, Rate of Compensation Increase

^[1]

7.25%

7.75%

8.00%

3.75%

3.79%

4.20%

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

Assumptions, Rate of Increase in Compensation Levels

3.44%

4.30%

4.95%

5.00%

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

Assumptions, Rate of Compensation Increase

5.00%

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]

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

3.85%

4.42%

5.03%

Parent Company [Member] | Pension Plans, Defined Benefit [Member]

2.00%

4.00%

5.00%

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

Parent Company [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

4.68%

5.50%

6.05%

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

Parent Company [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

4.70%

5.00%

6.10%

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

Black Hills Energy [Member] | Pension Plans, Defined Benefit [Member]

4.35%

5.00%

5.90%

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

Black Hills Energy [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

4.60%

5.40%

6.00%

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

Black Hills Energy [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

3.90%

4.40%

5.05%

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

Cheyenne Light [Member] | Pension Plans, Defined Benefit [Member]

4.35%

4.60%

5.15%

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

Cheyenne Light [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

5.55%

6.05%

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

Scenario, Forecast [Member] | Pension Plans, Defined Benefit [Member]

4.65%

5.50%

6.00%

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

Age, Lower Than Retirement [Member] | Parent Company [Member]

7.25%

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.75%

9.01%

4.50%

Age, Lower Than Retirement [Member] | Black Hills Energy [Member]

2027

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.75%

9.01%

4.50%

Age, Lower Than Retirement [Member] | Cheyenne Light [Member]

2027

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

7.75%

9.01%

4.50%

Age, Greater Than Retirement [Member] | Parent Company [Member]

2027

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.50%

9.01%

4.50%

Age, Greater Than Retirement [Member] | Black Hills Energy [Member]

2026

2027

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.50%

9.01%

4.50%

Age, Greater Than Retirement [Member] | Cheyenne Light [Member]

2026

2027

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

Health Care Cost Trend Rate Assumed for Next Fiscal Year

6.50%

9.01%

4.50%

Contractual Obligation, Fiscal Year Maturity [Abstract]

2026

2027

[1]	The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 net periodic pension cost.

Employee Benefit Plans Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2012 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	$ 13,034
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	13,953
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	14,890
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	15,982
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	17,013
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	102,883
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	1,286
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,463
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,462
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,540
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,586
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	7,949
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	3,136
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	3,350
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	3,399
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	3,419
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3,456
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 16,814

Commitments and Contingencies Commitments and Contingencies (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Unrecorded Unconditional Purchase Obligation, Due within One Year

$ 187,301

Unrecorded Unconditional Purchase Obligation, Due within Two Years

109,707

Unrecorded Unconditional Purchase Obligation, Due within Three Years

108,024

Unrecorded Unconditional Purchase Obligation, Due within Four Years

97,972

Unrecorded Unconditional Purchase Obligation, Due within Five Years

86,564

Unrecorded Unconditional Purchase Obligation, Due after Five Years

$ 222,002

Expiration Date of Contracts Maximum

P4Y

PacifiCorp Purchase Power Agreement [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2023

Public Service of Colorado Purchase Power Agreement [Member]

$ 13,224

$ 12,515

$ 12,936

PacifiCorp Transmission [Member]

^[1]

$ 0

97,988

110,575

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2023

Happy Jack Wind Purchase Power Agreeement [Member]

$ 1,215

1,215

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 03, 2028

Silver Sage Wind Power Purchase Agreement [Member]

$ 1,988

1,955

2,815

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 30, 2029

Cargill Power Purchase Agreement [Member]

$ 3,269

3,281

1,723

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2013

Busch Ranch Wind Farm [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

14.5

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Oct. 16, 2037

$ 502

$ 0

Basin Electric [Member]

Number of M W Capacity Purchased Under Long-term Contract | MW

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Mar. 13, 2013

Jointly Owned Utility Plant, Proportionate Ownership Share Percentage

50.00%

[1]

This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

Commitments and Contingencies Related Party (Details) $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($) MW
Purchase Option, Property [Member] \| Wygen I Generating Facility [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2022
Number of M W Capacity Purchased Under Long-term Contract	60
Asset Purchase Option \| $	$ 2.6
Power purchased [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of M W Capacity Purchased Under Long-term Contract	200
Lease Expiration Date	Dec. 31, 2031

Commitments and Contingencies Power Sales Agreements (Details)	12 Months Ended
	Dec. 31, 2012 MW
M D U, Montana Dakota Utilities [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	25
City Of Gillette [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	23
Basin Electric [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	40
Long-term Contract To Sell Electric Power, Date of Contract Expiration	Mar. 31, 2013
Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	Apr. 01, 2015
Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration	May 31, 2023
Neil Simpson I I [Member] \| Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	5
Neil Simpson I I [Member] \| Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	10
Wygen I I I Generating Facility [Member] \| Purchase Power Contract, MEAN, 5 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	5
Wygen I I I Generating Facility [Member] \| Purchase Power Contract, MEAN, 10 M W [Member]
Long-term Purchase Commitment [Line Items]
Number of MW Sold Under Long-Term Contract	10

Commitments and Contingencies Environmental Contingencies (Details) $ in Millions	Dec. 31, 2012 USD ($)
Electric Utilities [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Net	$ 3.9
Gas Utilities [Member] \| Manufactured Gas Plant [Member]
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.1
Loss Contingency, Range of Possible Loss, Minimum	2.9
Loss Contingency, Range of Possible Loss, Maximum	6.3
Loss Contingency Accrual, at Carrying Value	$ 3.1

Commitments and Contingencies Legal Proceedings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($)
Loss from Catastrophes [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 8.0

The value (monetary amount) of the award the plaintiff seeks in the legal matter.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 9
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14557-108349

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 4
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14435-108349

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 11
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Guarantees Guarantees (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2012

USD ($)

Gas Utilities [Member] | Natural Gas Storage and Transportation Supplier BP Energy [Member]

$ 175,273

$ 70,000

^[1]

Gas Utilities [Member] | Natural Gas Transportation and Storage Supplier Colorado interstate [Member]

Ongoing

$ 10,000

^[2]

Gas Utilities [Member] | Natural Gas Supplier Cross Timbers [Member]

P7M

$ 7,500

^[3]

Electric Utilities [Member] | Wind Turbines [Member]

P6M

$ 33,264

^[4]

Coal Mining [Member] | Surety Bonds [Member]

P2M29D

$ 54,509

^[5]

Ongoing

[1]	We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.
[2]	We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.
[3]	We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.
[4]	We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.
[5]	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Oil and Gas Reserves (Unaudited) Oil and Gas Narrative (Details) Mcfe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($) Gross-Well PUD_Location Mcfe State a	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Reserve Quantities [Line Items]
Operating and Non-Operating Interests, Wells \| Gross-Well	1,200
Gas and Oil Acreage, Leased \| a	268,636
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	5,600
Reserves Replaced, percentage	46.00%
Changes in Estimated Future Development Costs (USD) \| $	$ 43,854	$ 43,809	$ (17,125)
PUD Locations in Reserves for Five Or More Years (PUD) \| PUD_Location	0
Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	1,900
Proved Undeveloped Reserves, Revisions of Previous Estimates	500
Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	3,100
Capital Expenditure for Proved Undeveloped Reserve \| $	$ 5,700
PUD Development, PUD location \| PUD_Location	3
Proved Undeveloped Reserve (Volume)	1,400
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	11
Changes in Estimated Future Development Costs (USD) \| $	$ 7,000
San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	3,000
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Extensions, Discoveries, and Additions	300
Commodity Prices [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	27,051
Commodity Prices [Member] \| Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	13,900
Change in Future Development Costs \| $	$ 24,700
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	3
Commodity Prices [Member] \| Other Basins [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	400
Commodity Prices [Member] \| San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	11,500
Change in Future Development Costs \| $	$ 15,100
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	3
Commodity Prices [Member] \| Wind River Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	800
Commodity Prices [Member] \| Oklahoma Basin [Member] [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	500
Oil and Gas Reserve Revisions, Five Year Aging Limit [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	2,422
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	34
Oil and Gas Reserve Revisions, Five Year Aging Limit [Member] \| Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	2
Oil and Gas Reserve Revisions, Five Year Aging Limit [Member] \| Bear Paw Uplift [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	32
Oil and Gas Reserve Revisions, Performance [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	1,565
Added PUD Reserves [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	500
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	8
Changes in Estimated Future Development Costs (USD) \| $	$ 2,100
Oil and Gas Well Performance [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	1,600
Oil and Gas Asset Sold [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Change in Future Development Costs \| $	$ 41,700
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	9,500
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	29
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Oil and Gas Holds Wells \| State	9
Prior Year [Member] \| Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	900
Proved Undeveloped Reserve Locations (PUD) \| PUD_Location	3
Changes in Estimated Future Development Costs (USD) \| $	$ 4,900
Proved Undeveloped Reserves [Member] \| Commodity Prices [Member] \| Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	12,100
Proved Undeveloped Reserves [Member] \| Commodity Prices [Member] \| San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	8,100
Proved Undeveloped Reserves [Member] \| Oil and Gas Reserve Revisions, Five Year Aging Limit [Member] \| Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	1,400
Proved Undeveloped Reserves [Member] \| Oil and Gas Reserve Revisions, Five Year Aging Limit [Member] \| Bear Paw Uplift [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Revisions of Previous Estimates	1,000

Oil and Gas Reserves (Unaudited) Costs Incurred Oil and Gas (Details) - Oil and Gas [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Acquisition of Oil and Gas Properties, Proved Reserves	$ 2,437	$ 673	$ 0
Acquisition of Oil and Gas Properties, Unproved	33,052	8,317	3,846
Exploration Costs	115	44,384	8,159
Development Costs	73,877	38,638	25,264
Asset Retirement Obligation Incurred	158	43	1,228
Total costs incurred	$ 109,639	$ 92,055	$ 38,497

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have proved reserves.

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have unproved reserves.

Proved Developed And Undevleoped Reserves [Roll Forward]

Oil and Gas Reserves (Unaudited) Proved Developed and Undeveloped Oil and Gas Reserve (Details) (Details)
Mcfe in Thousands

12 Months Ended

Dec. 31, 2012

Mcfe

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2011

$ / bbl

$ / MMcf

MBbls

MMcf

Dec. 31, 2010

$ / bbl

$ / MMcf

MBbls

MMcf

Crude Oil Price, per Barrel, NYMEX | $ / bbl

94.71

96.19

79.43

Crude Oil Price Per Barrel, Wellhead | $ / bbl

85.31

88.49

70.82

Natural Gas Price Per MCF, NYMEX | $ / MMcf

2.76

4.12

4.38

Natural Gas Price Per MCF, Wellhead | $ / MMcf

2.24

3.59

3.45

Oil [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Balance at Beginning of Year | MBbls

6,223

5,940

5,274

Proved Developed and Undeveloped Reserves, Production | MBbls

^[1]

(560)

(452)

(376)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MBbls

(2,025)

^[2]

(84)

(13)

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries (bcfe) | MBbls

449

927

1,145

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MBbls

^[3]

(108)

(90)

Proved Developed and Undeveloped Reserves, Balance at End of Year | MBbls

4,116

6,223

5,940

Proved Developed Reserves (Volume) | MBbls

3,851

4,830

4,434

Proved Undeveloped Reserve (Volume) | MBbls

265

1,393

1,506

Natural Gas [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Balance at Beginning of Year | MMcf

95,904

95,456

87,660

Proved Developed and Undeveloped Reserves, Production | MMcf

^[1]

(8,686)

(8,526)

(8,484)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MMcf

(3,070)

^[2]

(377)

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries (bcfe) | MMcf

2,898

29,664

1,710

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf

(31,061)

^[3]

(20,690)

14,947

Proved Developed and Undeveloped Reserves, Balance at End of Year | MMcf

55,985

95,904

95,456

Proved Developed Reserves (Volume) | MMcf

54,086

71,867

67,656

Proved Undeveloped Reserve (Volume) | MMcf

1,901

24,037

27,800

Cost And Commodity Price Revisions [Member]

Reserve Quantities [Line Items]

Proved Undeveloped Reserves, Revisions of Previous Estimates | Mcfe

(27,051)

Oil and Gas Reserve Revisions, Five Year Aging Limit [Member]

Reserve Quantities [Line Items]

Proved Undeveloped Reserves, Revisions of Previous Estimates | Mcfe

(2,422)

Oil and Gas Reserve Revisions, Performance [Member]

Reserve Quantities [Line Items]

Proved Undeveloped Reserves, Revisions of Previous Estimates | Mcfe

(1,565)

[1]	Production for reserve calculations does not include volumes for natural gas liquids (NGLs).
[2]	Reflects the sale of the majority of the Williston Basin assets during 2012.
[3]	Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.

Oil and Gas Reserves (Unaudited) Capitalized Costs (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]

Capitalized Costs, Unproved Oil and Gas Properties

$ 59,526

$ 28,656

$ 28,160

Capitalized Costs, Proved Oil and Gas Properties

662,444

674,494

592,978

Gross Capitalized Costs, Oil and Gas Producing Activities

721,970

703,150

621,138

Capitalized Costs, Oil and Gas, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance

(534,777)

^[1]

(361,173)

(334,955)

Net Capitalized Costs, Oil and Gas Producing Activities

$ 187,193

$ 341,977

$ 286,183

[1]	Reflects the sale of the majority of the Williston Basin assets during 2012.

Oil and Gas Reserves (Unaudited) Results of Operations Oil and Gas (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Results of Operations, Revenue	$ 79,072	$ 79,808	$ 74,164
Results of Operations, Production Costs	23,483	23,820	21,922
Gain (Loss) on Sale of Property Plant Equipment	(29,129)	0	0
Results of Operations, Depreciation, Depletion and Amortization, and Valuation Provisions	37,323	34,415	29,013
Impairment of long-lived assets	26,868	0	0
Results of Operations, Total Costs	58,545	58,235	50,935
Results of Operations from Producing Activities, before Tax	20,527	21,573	23,229
Results of Operations, Income Tax (Expense) Benefit	(7,082)	(7,442)	(8,014)
Results of Operations, Producing Activities (Excluding General and Administrative Costs and Interest Costs)	$ 13,445	$ 14,131	$ 15,215

Oil and Gas Reserves (Unaudited) Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	$ 55,024
Exploration Costs, Excluded from Amortization Base	328
Capitalized Interest, Excluded from Amortization Base	4,174
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	59,526
Current Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	35,539
Exploration Costs, Excluded from Amortization Base	328
Capitalized Interest, Excluded from Amortization Base	683
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	36,550
Prior Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	638
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	60
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	698
More Than One Year, Less Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	2,138
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	(36)
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	2,102
More Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold Acquisition Costs	16,709
Exploration Costs, Excluded from Amortization Base	0
Capitalized Interest, Excluded from Amortization Base	3,467
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	20,176
Oil and Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 700	$ 900	$ 800

Oil and Gas Reserves (Unaudited) Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Cash Inflows, Standardized Measure of Discounted Future Net Cash Flows	$ 502,769	$ 931,637	$ 764,585
Future Production Costs, Standardized Measure of Discounted Future Net Cash Flows	(186,695)	(280,910)	(256,455)
Future Development Costs, Standardized Measure of Discounted Future Net Cash Flows	(8,462)	(92,233)	(73,805)
Future Income Tax Expense, Standardized Measure of Discounted Future Net Cash Flows	(69,877)	(157,922)	(111,666)
Future Net Cash Flows, Standardized Measure of Discounted Future Net Cash Flows	237,735	400,572	322,659
10 Percent Annual Discount for Estimated Timing of Cash Flows, Standardized Measure of Discounted Future Net Cash Flows	(101,632)	(197,215)	(154,551)
Standardized Measure of Discounted Future Net Cash Flow	$ 136,103	$ 203,357	$ 168,108

Oil and Gas Reserves (Unaudited) Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]

Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year

$ 203,357

$ 168,108

$ 129,108

Sales and Transfers of Oil and Gas Produced, Net of Production Costs

(48,905)

(52,914)

(40,282)

Net Change in Prices and Production Costs

(42,639)

57,087

57,380

Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs

19,870

31,179

17,076

Changes in Estimated Future Development Costs (USD)

43,854

43,809

(17,125)

Development Costs Incurred During Period

21,931

18,940

4,975

Revisions of Previous Quantity Estimates (USD)

(86,277)

(58,211)

27,513

Accretion of Discount

25,509

19,655

13,434

Changes in Income Taxes, Estimates on Future Cash Flows, Proved Oil and Gas Reserves

36,578

(23,283)

(23,233)

Increase Due to Purchases of Reserves

Decrease Due to Sales Reserves

(37,175)

^[1]

(1,013)

(738)

Standardized Measure of Discounted Future Net Cash Flows, End of Year

$ 136,103

$ 203,357

$ 168,108

[1]	Reflects the sale of the majority of the Williston Basin assets during 2012.

Sale of Operating Assets Sale of Assets (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Sep. 27, 2012

USD ($)

Acres

Gross-Well

Sep. 18, 2012

USD ($)

Jul. 14, 2010

USD ($)

Mar. 01, 2010

USD ($)

Dec. 31, 2012

USD ($)

Sep. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Significant Acquisitions and Disposals [Line Items]

$ 1,800

$ 27,300

$ 29,129

$ 0

$ 8,921

Significant Acquisitions and Disposals [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share Percentage

50.00%

Significant Acquisitions and Disposals [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share Percentage

44.70%

Busch Ranch Wind Farm [Member] | Electric Utilities [Member]

Significant Acquisitions and Disposals [Line Items]

Proceeds from Sale of Property, Plant, and Equipment

$ 25,000

Wygen I I I Generating Facility [Member] | Electric Utilities [Member]

Significant Acquisitions and Disposals [Line Items]

Jointly Owned Utility Plant, Proportionate Ownership Share Percentage

52.00%

23.00%

Proceeds from Sale of Property, Plant, and Equipment

$ 62,000

Property, Plant and Equipment, Disposals

55,800

Williston Basin Assets [Member] | Oil and Gas [Member]

$ 6,200

Significant Acquisitions and Disposals [Line Items]

Productive Oil Wells, Number of Wells, Gross | Gross-Well

$ 29,100

Oil and Natural Gas Acreage, Leased (acres) | Acres

28,000

Effective Date, Disposal

Jul. 01, 2012

Proceeds from Sale of Productive Assets [Abstract]

Post Close Adjustment

$ 2,793

Elkhorn Territory [Member] [Member] | Gas Utilities [Member]

Significant Acquisitions and Disposals [Line Items]

Proceeds from Sale of Property, Plant, and Equipment

$ 6,100

Cash Proceeds Received on Date of Sale [Member] | Williston Basin Assets [Member] | Oil and Gas [Member]

$ 2,700

Proceeds from Sale of Productive Assets [Abstract]

Proceeds from Sale of Oil and Gas Property and Equipment

243,314

Net Cash Proceeds from Sale of Oil and Gas Property and Equipment

243,314

Net Cash Proceeds [Member] | Williston Basin Assets [Member] | Oil and Gas [Member]

Proceeds from Sale of Productive Assets [Abstract]

Proceeds from Sale of Oil and Gas Property and Equipment

227,860

Net Cash Proceeds from Sale of Oil and Gas Property and Equipment

227,860

Transaction advisor fees [Member] | Williston Basin Assets [Member] | Oil and Gas [Member]

Proceeds from Sale of Productive Assets [Abstract]

Transaction Costs

(1,400)

Estiamted Payment of Contractual Obligation Realted to Back-In Fee [Member] | Williston Basin Assets [Member] | Oil and Gas [Member]

Proceeds from Sale of Productive Assets [Abstract]

Transaction Costs

^[1]

$ (16,847)

Busch Ranch Wind Farm [Member]

Significant Acquisitions and Disposals [Line Items]

Number of M W Capacity Purchased Under Long-term Contract | MW

14.5

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Oct. 16, 2037

[1]	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

Discontinued Operations Narrative, Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Date	Feb. 29, 2012
Proceeds from Divestiture of Businesses	$ 107,511	$ 0	$ 0
Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Funds Retained, Sale of Business	57,500
Maximum [Member] \| Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Post Close Adjustment	7,200
Minimum [Member] \| Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Post Close Adjustment	$ 1,400

Discontinued Operations Balance Sheet and Income Statement of Discontinued Operations (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]

Income (Loss) from Discontinued Operations, Net of Tax

$ (167)

$ (166)

$ (1,160)

$ (5,484)

$ 6,839

$ 638

$ 4,046

$ (2,158)

Business Exit Costs

$ 2,500

Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]

Net Assets, Discontinued Operations

$ 0

340,851

$ 340,851

Energy Marketing [Member]

Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]

Revenue, Discontinued Operations

(604)

41,101

$ 27,999

Pre-tax Income (Loss) from Discontinued Operations

(6,061)

14,838

8,673

Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax

(4,184)

Income Tax (Expense) Benefit, Discontinued Operations

3,268

(5,473)

(3,129)

Income (Loss) from Discontinued Operations, Net of Tax

$ (6,977)

^[1]

9,365

$ 5,544

Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]

Discontinued Operation, Other Current Assets

280,221

Discontinued Operations, Derivative Assets, Current and Non-Current

52,859

Discontinued Operation, Property, Plant, and Equipment, Net

5,828

Discontinued Operation, Goodwill

1,435

Discontinued Operation, Noncurrent Assets

508

Discontinued Operation, Other Current Liabilities

(132,951)

Discontinued Operations, Derivative Liabilities, Current and Non-Current

(26,084)

Discontinued Operation, Other Non-current Liabilities

(14,894)

Net Assets, Discontinued Operations

$ 166,922

[1]	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended Dec. 31, 2012.

Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Selected Quarterly Financial Information [Line Items]

$ 318,862

$ 246,808

$ 242,363

$ 365,851

$ 361,181

$ 249,523

$ 260,649

$ 400,835

$ 1,173,884

$ 1,272,188

$ 1,219,691

Operating Income

75,262

^[1]

77,810

^[1]

20,591

^[1]

70,048

52,140

39,572

36,160

58,367

243,711

186,239

183,420

Income (Loss) from Discontinued Operations, Net of Tax

30,934

^[2],[3]

34,623

^[2],[3]

(12,323)

^[2],[3]

35,271

^[2]

18,754

^[4]

(11,163)

^[4]

3,706

^[4]

29,068

^[4]

88,505

40,365

63,141

(167)

(166)

(1,160)

(5,484)

6,839

638

4,046

(2,158)

Income (Loss) from Continuing Operations, Per Basic Share

$ 30,767

^[2],[3]

$ 34,457

^[2],[3]

$ (13,483)

^[2],[3]

$ 29,787

$ 25,593

^[4]

$ (10,525)

^[4]

$ 7,752

^[4]

$ 26,910

^[4]

$ 81,528

$ 49,730

$ 68,685

$ 0.70

$ 0.79

$ (0.28)

$ 0.81

$ 0.45

$ (0.29)

$ 0.09

$ 0.74

$ 2.02

$ 1.01

$ 1.62

Income (Loss) from Discontinued Operations, Net of Tax, Per Basic Share

0.00

(0.03)

(0.13)

0.16

0.02

0.11

(0.05)

(0.16)

0.24

0.14

Total Income (loss) per share, Basic

0.70

0.79

(0.31)

0.68

0.61

(0.27)

0.20

0.69

1.86

1.25

1.76

Income (Loss) from Continuing Operations, Per Diluted Share

0.70

0.78

(0.28)

0.80

0.44

(0.29)

0.09

0.73

2.01

1.01

1.62

Income (Loss) from Discontinued Operations, Net of Tax, Per Diluted Share

0.00

(0.03)

(0.12)

0.16

0.02

0.10

(0.05)

(0.16)

0.23

0.14

Total Income (loss) per share, Diluted

0.70

0.78

(0.31)

0.68

0.60

(0.27)

0.19

0.68

1.85

1.24

1.76

Dividends Paid Per Share

0.370

0.365

$ 1.48

$ 1.46

$ 1.44

Common Stock Prices - High

37.00

36.28

34.31

35.82

34.47

32.22

34.85

33.64

Common Stock Prices - Low

$ 33.51

$ 30.29

$ 31.32

$ 32.18

$ 29.10

$ 25.83

$ 28.12

$ 29.76

Impairment of Oil and Gas Properties

$ 26,900

$ 26,868

^[5]

$ 0

Increase Decrease in Fair Value of Unhedged Derivative Instrument After Tax

$ 1,800

$ 27,300

$ 29,129

$ 0

$ 8,921

3,100

400

(10,100)

$ 7,800

$ (900)

$ (24,900)

$ (5,100)

$ 3,600

Impairment of Oil and Gas Properties After Tax

$ 17,300

Gain (Loss) On Sale Of Oil And Gas Properties, After-Tax

$ 1,200

$ 17,700

[1]	(a)Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.
[2]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.
[3]	Second quarter includes an after-tax ceiling test impairment loss of $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.
[4]	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.
[5]	Oil and Gas includes a ceiling test impairment (see Note 12).

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Statement of Income for Parent Company (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2012

^[1]

Sep. 30, 2012

^[1]

Jun. 30, 2012

^[1]

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Condensed Financial Statements, Captions [Line Items]

Operating expenses

$ 930,173

$ 1,085,949

$ 1,036,271

Equity in earnings (loss) in earnings of subsidiaries

$ 75,262

$ 77,810

$ 20,591

$ 70,048

$ 52,140

$ 39,572

$ 36,160

$ 58,367

243,711

186,239

183,420

Other income (expense):

1,121

1,559

(113,610)

^[2]

(91,383)

(90,606)

1,882

(42,010)

(15,193)

1,957

2,017

541

Total other income (expense)

2,965

3,726

7,148

(106,816)

(128,771)

(99,669)

(48,400)

(18,224)

(22,169)

81,528

49,730

68,685

Condensed Financial Statements, Captions [Line Items]

Operating expenses

831

772

735

Equity in earnings (loss) in earnings of subsidiaries

(831)

(772)

(735)

Other income (expense):

93,479

87,150

88,627

(19,665)

(15,229)

(14,985)

1,882

(42,010)

(15,193)

Total other income (expense)

(42)

75,777

29,872

58,505

Income (loss) from continuing operations before income taxes

74,946

29,100

57,770

6,582

20,630

10,915

$ 81,528

$ 49,730

$ 68,685

[1]	(a)Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.
[2]	Corporate includes a make-whole provision from early repayment of long-term debt (see Note 8).

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Statement of OCI (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Net income (loss) available for common stock	$ 81,528	$ 49,730	$ 68,685
Benefit plan liability adjustment - net gain (loss) (net of tax of $296, $4,135 and $674, respectively)	(542)	(7,609)	(1,307)
Benefit plan liability adjustments - prior service (costs) (net of tax of $86, $176 and $111, respectively)	(157)	(325)	(214)
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $887, $1,708 and $(636), respectively)	(1,268)	(2,831)	1,336
Reclassification adjustment of cash flow hedges settled and included in net income (loss) (net of tax of $534, $(709) and $2,498, respectively)	(643)	1,468	(4,232)
Other comprehensive income (loss), net of tax	(2,610)	(9,297)	(4,417)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	78,918	40,433	64,268
Other Comprehensive Income (Loss), Tax, Parenthetical Disclosures [Abstract]
Other Comprehensive Income (Loss), Benefit Plans, Net (Gain) Loss, Tax	(296)	(4,135)	(674)
Other Comprehensive Income (Loss), Amortization, Benefit Plans, Prior Service Cost, Tax	86	176	111
Other Comprehensive Income (Loss), Fair Value Adjustment on Derivatives Designated as Cash Flow Hedges, Tax	(887)	(1,708)	636
Other Comprehensive Income (Loss), Reclassification Adjustment of Cash Flow Hedges Setteled and Included in Net Income, Tax	$ (534)	$ 709	$ (2,498)

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Balance Sheet for Parent Company Only (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current assets:
Cash and cash equivalents	$ 15,462	$ 21,628
Income Taxes Receivable, Current	0	9,344
Deferred income tax assets, net, current	77,231	37,202
Other current assets	28,795	21,266
Total current assets	405,106	758,921
Property, Plant and Equipment, Net	2,742,749	2,789,575
Other assets, non-current	19,420	19,941
Total other assets, non-current	565,214	561,326
TOTAL ASSETS	3,729,471	4,127,083
Current liabilities:
Accounts payable	84,422	104,748
Derivative liabilities, current	96,541	84,367
Notes payable	277,000	345,000
Current maturities of long-term debt	103,973	2,473
Total current liabilities	734,889	878,067
Derivative liabilities, non-current	16,941	49,033
Long-term debt, excluding current maturities	938,877	1,280,409
Stockholders' Equity Attributable to Parent	1,232,509	1,209,336	$ 1,100,270	$ 1,084,837
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	3,729,471	4,127,083
Black Hills Corporation [Member]
Current assets:
Cash and cash equivalents	1,266	3,114	$ 219	$ 2,273
Accounts receivable - affiliates, current	2,194	1,445
Notes receivable, affiliates, current	637,586	453,216
Income Taxes Receivable, Current	5,843	8,653
Deferred income tax assets, net, current	29,779	36,951
Other current assets	4,887	7,178
Total current assets	681,555	510,557
Property, Plant and Equipment, Net	1,135	1,135
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	1,194,501	1,339,024
Notes Receivable, Related Parties, Noncurrent	250,000	575,000
Deferred Tax Assets, Net, Noncurrent	41,494	29,454
Other assets, non-current	4,014	4,834
Total other assets, non-current	295,508	609,288
TOTAL ASSETS	2,172,699	2,460,004
Current liabilities:
Accounts payable	565	5,202
Derivative liabilities, current	91,617	78,502
Notes payable	277,000	345,000
Notes payable - affiliate, current	1,032	1,754
Current maturities of long-term debt	100,000	0
Other liabilities, current	9,943	12,070
Total current liabilities	480,157	442,528
Derivative liabilities, non-current	9,252	31,368
Long-term debt, excluding current maturities	450,000	774,959
Notes payable - affiliates, non-current	781	1,813
Total long-term debt	450,781	776,772
Stockholders' Equity Attributable to Parent	1,232,509	1,209,336
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 2,172,699	$ 2,460,004

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Parent Cash Flow Statement (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating activities:
Net income (loss) available for common stock									$ 81,528	$ 49,730	$ 68,685
Income (Loss) from Discontinued Operations, Net of Tax	$ 167	$ 166	$ 1,160	$ 5,484	$ (6,839)	$ (638)	$ (4,046)	$ 2,158
Income (loss) from continuing operations									88,505	40,365	63,141
Adjustments to reconcile income (loss) to net cash provided by operating activities:
Equity in earnings of subsidiaries									(10)	(1,121)	(1,559)
Stock compensation									8,271	5,643	5,637
Unrealized mark-to-market (loss) gain on interest rate swaps, net									(1,882)	42,010	15,193
Derivative fair value adjustments									2,728	(8,693)	13,546
Deferred Income Tax Expense (Benefit)									39,716	33,600	17,354
Other adjustments, net									2,751	4,947	(9,710)
Changes in certain operating assets and liabilities:
Accounts receivable and other current assets									(2,257)	(4,202)	(18,480)
Other operating activities, net									(6,732)	(11,118)	(1,013)
Net cash provided by (used in) operating activities of continuing operations									295,787	216,694	156,565
Investing activities:
Payments for (Proceeds from) Other Investing Activities									(180)	(4,533)	15,407
Net cash provided by (used in) investing activities									11,169	(447,007)	(389,168)
Financing activities:
Common stock issued									4,726	123,041	3,246
Long-term debt - issuance									0	0	200,000
Repayments of Long-term Debt									(240,077)	(8,382)	(59,926)
Other financing activities									(2,833)	(1,666)	(8,363)
Net cash provided by (used in) financing activities									(371,446)	249,633	160,953
Net change in cash and cash equivalents									(43,306)	26,330	(80,463)
Cash and cash equivalents, at carrying value	15,462				21,628				15,462	21,628
Supplemental Cash Flow Information [Abstract]
Income Taxes Paid, Net									(3,027)	9,854	9,384
Black Hills Corporation [Member]
Operating activities:
Net income (loss) available for common stock									81,528	49,730	68,685
Income (Loss) from Discontinued Operations, Net of Tax									0	0	0
Income (loss) from continuing operations									81,528	49,730	68,685
Adjustments to reconcile income (loss) to net cash provided by operating activities:
Equity in earnings of subsidiaries									(93,479)	(87,150)	(88,627)
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries									0	14,500	6,298
Stock compensation									8,271	5,643	5,637
Unrealized mark-to-market (loss) gain on interest rate swaps, net									(1,882)	42,010	15,193
Derivative fair value adjustments									(4,339)	2,291	(6,384)
Deferred Income Tax Expense (Benefit)									(8,116)	2,599	(34,452)
Other adjustments, net									3,909	4,376	2,508
Changes in certain operating assets and liabilities:
Accounts receivable and other current assets									6,541	(5,141)	2,198
Increase (Decrease) in Accounts Payable and Accrued Liabilities									(6,764)	3,550	4,846
Other operating activities, net									(3,477)	550	(2,514)
Net cash provided by (used in) operating activities of continuing operations									(17,808)	32,958	(26,612)
Investing activities:
Payments to Acquire Property, Plant, and Equipment									0	(1,135)	0
Proceeds from (Repayments of) Related Party Debt									96,073	(258,117)	(216,337)
Payments for (Proceeds from) Other Investing Activities									450	0	0
Net cash provided by (used in) investing activities									96,523	(259,252)	(216,337)
Financing activities:
Payments of Dividends, Common Stock									(65,262)	(59,202)	(56,467)
Common stock issued									4,726	123,041	3,246
Repayments of Short-term Debt									(271,753)	(821,300)	(770,000)
Proceeds from Short-term Debt									203,753	1,017,300	854,500
Increase (Decrease) in Notes Payable, Related Parties									275,806	(25,302)	14,995
Long-term debt - issuance									0	0	200,000
Repayments of Long-term Debt									(225,000)	0	0
Other financing activities									(2,833)	(5,348)	(5,379)
Net cash provided by (used in) financing activities									(80,563)	229,189	240,895
Net change in cash and cash equivalents									(1,848)	2,895	(2,054)
Cash and cash equivalents, at carrying value	$ 1,266				$ 3,114				1,266	3,114	219	$ 2,273
Supplemental Cash Flow Information [Abstract]
Notes Reduction									40,039	0	62,019
Other Significant Noncash Transaction, Value of Consideration Received									(277,560)	0	13,874
Non-cash Dividends Paid to Parent by Subsidiaries									237,521	0	0
Interest Paid									(18,550)	(14,667)	(56,464)
Income Taxes Paid, Net									$ 3,911	$ 23,830	$ (504)

Schedule I Disclosures for Parent Company Only Schedule I, Schedule of Dividends Paid to Parent (Details) - Black Hills Corporation [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Dividend Paid to Parent [Line Items]
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries	$ 0	$ 14,500	$ 6,298
Non-cash Dividends Paid to Parent by Subsidiaries	$ 237,521	$ 0	$ 0

Schedule I Disclosures for Parent Company Only Schedule I, Long Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Oct. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Current maturities of long-term debt

$ 103,973

$ 2,473

Long-term Debt, Fiscal Year Maturity [Abstract]

938,877

1,280,409

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

103,973

Long-term Debt, Maturities, Repayments of Principal in Year Two

256,023

Long-term Debt, Maturities, Repayments of Principal in Year Three

6,963

Long-term Debt, Maturities, Repayments of Principal in Year Four

78,947

Long-term Debt, Maturities, Repayments of Principal in Year Five

Long-term Debt, Maturities, Repayments of Principal after Year Five

597,055

Current maturities of long-term debt

^[1]

550,000

774,959

100,000

Potential Future Exposure on Credit Related Contingent Feature

450,000

774,959

100,000

1,000

Long-term Debt, Fiscal Year Maturity [Abstract]

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

100,000

Long-term Debt, Maturities, Repayments of Principal in Year Two

250,000

Long-term Debt, Maturities, Repayments of Principal in Year Three

Long-term Debt, Maturities, Repayments of Principal in Year Four

Long-term Debt, Maturities, Repayments of Principal in Year Five

Long-term Debt, Maturities, Repayments of Principal after Year Five

$ 200,000

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2013 [Member]

May 15, 2013

6.50%

Debt Instrument, Unamortized Discount

^[1]

$ 225,000

$ 0

^[2]

$ 0

Debt Instrument, Early Repayment Date

Oct. 31, 2012

Black Hills Corporation [Member] | Senior Unsecured Notes Due 2014 [Member]

May 15, 2014

9.00%

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

^[1]

$ 250,000

^[3]

250,000

Jul. 15, 2020

5.88%

Black Hills Corporation [Member] | Corporate Term Loan due September 2013 [Member]

^[1],[4]

$ 200,000

200,000

Sep. 30, 2013

^[5]

1.63%

^[5]

$ 100,000

[1]	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.
[2]	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.
[3]	This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.
[4]	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.
[5]	Variable interest rates; rates presented are as of Dec. 31, 2012.

Schedule I Disclosures for Parent Company Only Schedule I, Derivative Instruments Statement of Financial Postion Location and Notional Amount (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

$ 96,541

$ 84,367

Designated as Hedging Instrument [Member]

$ 16,941

$ 49,033

Derivative, Remaining Maturity

4 years

5 years

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

^[1]

$ 150,000

5.04%

$ 7,039

$ 6,513

Pre-tax accumulated other comprehensive income (loss)

16,941

20,363

(23,980)

(26,876)

Gain (Loss) on Derivative Instruments, Net, Pretax

Derivative, Fair Value, Amount Offset Against Collateral, Net

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

7,000

91,617

78,502

Black Hills Corporation [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

9,252

31,368

^[1]

$ 75,000

Derivative, Remaining Maturity

4.97%

4 years

5 years

$ 3,469

$ 3,207

Pre-tax accumulated other comprehensive income (loss)

9,252

10,672

(12,721)

(13,879)

Gain (Loss) on Derivative Instruments, Net, Pretax

Derivative, Collateral, Right to Reclaim Cash

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

3,500

Black Hills Corporation [Member] | Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]

^[1],[2]

$ 250,000

Derivative, Remaining Maturity

5.67%

1 year

2 years

$ 88,148

$ 75,295

Pre-tax accumulated other comprehensive income (loss)

20,696

Gain (Loss) on Derivative Instruments, Net, Pretax

1,882

(42,010)

Derivative, Fair Value, Amount Offset Against Collateral, Net

5,960

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

Derivatives, Carrying Amount and Fair Value [Line Items]

$ 75,000

[1]	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.
[2]	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.

Schedule I Disclosures for Parent Company Only Schedule I, Fair Value by Balance Sheet Grouping (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 15,462

$ 21,628

Long-term Debt, including current maturities

277,000

345,000

1,042,850

1,282,882

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

15,462

21,628

Long-term Debt, including current maturities

277,000

345,000

1,042,850

1,282,882

Total Estimate of Fair Value, Fair Value Disclosure [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

Cash and cash equivalents, at fair value

^[1]

15,462

21,628

Notes payable, fair value

^[1]

277,000

345,000

Long-term debt, including current maturities, at fair value

^[2]

1,231,559

1,464,289

Derivatives, Carrying Amount and Fair Value [Line Items]

1,266

3,114

$ 219

$ 2,273

Black Hills Corporation [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]

277,000

345,000

Derivatives, Carrying Amount and Fair Value [Line Items]

1,266

3,114

Long-term Debt, including current maturities

277,000

345,000

550,000

774,959

Black Hills Corporation [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

Derivatives, Carrying Amount and Fair Value [Line Items]

Cash and cash equivalents, at fair value

^[1]

1,266

3,114

Notes payable, fair value

^[1]

277,000

345,000

Long-term debt, including current maturities, at fair value

^[2]

$ 615,239

$ 851,241

[1]

[2]

Schedule II Consolidated Valuation and Qualifying Accounts Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2009
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for Doubtful Accounts, Balance at Beginning of Year		$ 2,295	$ 3,683
Allowance for Doubtful Accounts, Adjustments	$ 0	0	0
Allowance for Doubtful Accounts, Charged to Cost and Expense	1,913	3,042	1,898
Allowance for Doubtful Accounts, Recoveries and Other Additions	3,822	5,369	2,196
Allowance for Doubtful Accounts, Write-Offs and Other Deductions	(6,628)	(9,045)	(5,482)
Allowance for Doubtful Accounts, Balance at End of Year	$ 768	$ 1,661	$ 2,295

Label	Element	Value
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents	us-gaap_DisposalGroupIncludingDiscontinuedOperationCashAndCashEquivalents	$ 97,500,000

For the disposal group, including a component of the entity (discontinued operation), cash includes currency on hand as well as demand deposits with banks or financial institutions. Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months.